Comstock Resources, Inc. (CRK) Q2 2018 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the Q2 2018 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions] Also as a reminder, this conference call is being recorded. At this time, I would like to turn the call over to your host to the CEO, Jay Allison. Please go ahead, sir.

Alright. Thank you. Welcome to the Comstock Resources second 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 entitled Second 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 second quarter operating and financial results as well as provide an update on the Jerry Jones contribution and our comprehensive refinancing plans. 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. If you will flip forward to Slide 3, our 2018 second quarter summary. We expect to complete the contribution transaction through which Jerry Jones will contribute as Bakken Shale properties valued at $620 million to the company for 84% of our common stock on August 14. We will use the cash from these properties, which is around $200 million tier to fund an expanded Haynesville shale drilling program to drive our growth. We also will complete our comprehensive refinancing plan simultaneously with the contribution. We will retire all of our existing debt with borrowings under the new bank credit facility, with a $700 billion borrowing base and a $850 million in new 8-year unsecured notes that we sold in a private placement on July 20. Our Haynesville/Bossier shale program continues to deliver strong results. We have had very consistent results in our Haynesville drilling program. Since we restarted our drilling program in the Haynesville with an enhanced completion design in 2015, we have drilled and completed 52 operated wells, which have an average IP rate of 25 million cubic feet equivalent per day. This drilling program will grow our natural gas production by 30% in 2018 and 50% in 2019. We also announced that on July 31 we completed an attractive bolt-on Haynesville shale acquisition, which added approximately 9,900 net and 112 or 31.0 net un-drilled locations. I will provide some details on the Jones assets and the Haynesville acquisition in the next couple of slides. If you go to Slide 4, we summarized the Jerry Jones asset contribution. Jerry Jones will contribute North Dakota producing oil and gas properties that he holds the 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. So we will receive a net cash flow from these properties from April 1 to August 14, which is estimated to be $48 million after capital expenditures. Jerry Jones 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 last condition to meet in order to close the transaction is approval by our shareholders at the upcoming annual meeting this Friday. The contribution is providing us with substantial cash flow, which we will invest in our high return Haynesville shale drilling program. The proved reserve value and related cash flows from the contributed properties when combined with our properties have allowed us to put a new bank credit facility in place and issue $850 million of new 8-year unsecured notes where we used the proceeds from the notes offerings together with cash on the balance sheet and borrowings under the bank credit facility to fund the tender offer for all of our outstanding senior notes. The tender offer expires this Friday, August 10. Slide 5 is an overview of the properties that we will be acquiring. The acquisition includes 348 producing oil wells, 55.1 net in North Dakota and Montana producing from the Bakken Shale. The wells have been drilled over the last 5 years. There are also 85 drilled uncompleted wells or 11.8 net that are expected to be completed later this year and 7 or 2.6 net un-drilled wells. That production from these wells in the first quarter was approximately 10,400 barrels of oil per day and 17 million cubic feet of natural per day. Our independent reserve engineers have estimated the proved reserves of 22.8 million barrels of oil and 49.3 billion cubic feet of natural gas. Based on current oil and gas prices, we expect to acquire the acquired properties to generate approximately $200 million of operating cash flow in 2018. Slide 6 shows you the properties we acquired from the bankruptcy slate of Enduro Resource Partners. These properties consists of approximately 21,000 gross acres or 9,900 net primarily in Caddo and DeSoto Parishes in Louisiana and included 120 or 26.2 net producing natural gas wells, 49 or 14.7 net of the wells are Haynesville wells. The final adjusted purchase price was $37 million which included cost of four 1.1 net recently completed Haynesville Shale wells incurred after the effective date of the sale January 1, 2018. The Enduro properties were producing approximately 26 cubic feet per day of natural gas and estimated proved reserves of 288 Bcfe. We have identified 112 or 31.0 net potential drilling locations on the acquired acreage, 21 or 17.9 net of the future locations will be operated by us. I will now ask Roland Burns to go over the second quarter financial results. Ronald?

Thanks Jay. On Slide 7, we summarized our second quarter financial results. Higher natural gas production and lower operating costs were offset by lower natural gas prices and the sale of our Eagle Ford shale oil production. Our natural gas production was up 25% in the second quarter, but natural gas prices were down 12%. Oil and gas sales this quarter were $63 million and our EBITDAX came in at $44 million. Operating cash flow for the quarter was $26 million. We did see continued improvement of many of our operating cost items. Our lifting costs decreased 4% despite the 19% higher production level and our depreciation, depletion and amortization per unit was down 12% due to overall improved finding costs from the Haynesville Shale program. Our G&A costs this quarter came in at $7 million and with higher than the second quarter of 2017 only due to the inclusion of about $400,000 in costs related to the unsuccessful tender offer that we made back on April 4 – on April 2 actually. For the quarter we reported a loss of $34 million or $2.22 per share. Those results included several unusual items including our unrealized mark to market loss and our hedge position of $2.7 billion, the non-cash amortization of the large discounts recognized in the 2016 bond exchange of 12.2 million which is included in the interest expense. Of course the $400,000 of cost related to the unsuccessful tender offer and then also a $6.8 million loss on property sales. Excluding these items our loss would have been $11.9 million or $0.78 per share. On Slide 8, we summarized the financial results for the first half of this year. For the first six months our natural gas production was up 38%, natural gas prices were down by about 8%. Overall, oil and gas sales were up 17% to $137 million, our EBITDAX was $98 million, which is 25% higher than the same period in 2017. Our operating cash flow was $62 million and that’s up 48% from what it was in 2017. Our lifting costs for the first 6 months were only 1% higher due to – despite the fact that we had a 31% over higher production level then our DD&A was down 10%. We had a loss of $76 million for the 6 months or $4.99 per share. This item included many of the same unusual items, including the unrealized mark-to-market loss on our hedge contracts of $1.5 million, the non-cash amortization of the discount recognized on the bond exchange of $23.2 million, the $400,000 of cost related to the unsuccessful tender offer, and $35.4 million of loss on property sales primarily related to the Eagle Ford shale. Without these items, the loss would have been $15.4 million for the first 6 months this year or about $1.01 per share. On Slide 9, we recapped what production we had shut in for the quarter. And as you have seen from our press release that our natural gas production this quarter was substantially impacted by shut-in production related to offset frac activity and also due to pipeline curtailments, we had to curtail production from our North Haynesville operations in Caddo Parish during much of the quarter to allow Kinder Morgan to upgrade their facilities to handle all the new production from the wells that we have drilled. In total, our shut-in volumes averaged 19.1 million per day during the second quarter, which is much higher than the 5 million that we had shut-in in the first quarter. The pipeline curtailments have continued through the month of July and we anticipate being able to bring in all of our production in that area by early next week. On Slide 10, we show how our producing costs continue to improve quarter-over-quarter as the lower cost Haynesville shale production becomes a larger percentage of our total production. In the second quarter, our operating costs fell to $0.60 per Mcfe as compared to $0.75 per Mcfe in the second quarter of 2017 and even $0.70 in the first quarter of this year. Making up the overall lifting costs were gathering costs, which were $0.20, production taxes which average $0.05 and then our remaining field level operating cost averaged $0.35 per Mcfe produced in the second quarter. Our DD&A per Mcfe fell to $1.19 in the second quarter as compared to $1.60 in 2017 second quarter. On Slide 11, we summarized our hedge position that we had in place for our natural gas production. So, starting with the third quarter, we have 120 million per day of our gas production hedged. Half of that is with the price swap at $3 per MCF and the other half is in collars with 54 floors, with ceilings of 350 – ceilings of 330 to 350 per MCF. Our plan is to hedge 50% to 60% of our production going forward kind of on a rolling 12-month basis. So, we do plan to properly hedge our oil production relating to the Bakken properties as soon as the sale closes next week. Slide 12 presents our balance sheet at the end of the quarter and we also show the numbers pro forma for the August 14 closing of the Jones contribution and the refinancing of all our debt. So, we ended this quarter with $158 million in cash. We also had $1.2 billion in total debt. As we announced earlier, we have a commitment for a new 5-year bank credit facility with initial borrowing base of $700 million and we have issued $150 million of 8-year unsecured senior notes, which bear interest at 9.75%. These new notes were issued at 96% of par and the proceeds are being held in escrow until the contribution transaction was completed next week. We also have a tender offer out for all of our existing senior notes and that will close this Friday, August 10. So, on August 14, we plan to close the asset contribution, issue the new shares and then enter into the new bank credit facility, then we will fund the tender offer with proceeds, which will be released from escrow from the $850 million notes offering and we also have borrowings under the credit facility and we will use some of the cash on our balance sheet. So after paying all the transactions costs, our pro forma cash would be about $37 million and we would have $340 million outstanding under the new credit facility along with $850 million of new bonds. So, on a pro forma basis, our liquidity after closing will be about $400 million. On Slide 13 we show our pro forma SEC proved oil and gas reserves as of April 1, 2018 which was the effective date of the property contribution. So, we had a new third-party report done in connection with the financing that we have recently finished. The reserves presented on Slide 13 exclude the Eagle Ford properties that we sold in April, but they do include the Bakken Shale properties that are being contributed. The reserves also exclude any reserves related to the Enduro acquisition that we closed on July 31 as that was not in place when we prepared this outside reserve report. Overall, we had 2.3 Tcfe of proved reserves on that April 1 date, 37% of those volumes were developed and 90% were natural gas. The PV10 value of our proved reserves was $1.3 billion based on SEC prices for that period of $49.70 for oil and $2.89 for gas. Current oil prices are substantially higher than the SEC prices while the natural gas prices are really fairly similar to the SEC prices. So 87% of the proved reserves are our Haynesville-Bossier reserves, 8% are in the Bakken Shale of just on a volume basis. If you look on a value basis, the Bakken makes up one-third of the PV10 value. The proved undeveloped locations in the reserve report were booked on a conservative drill within cash flow drilling program and are limited only 5 years of drilling based on the SEC rules. So as such, the proved reserves that we are presenting here include only 239 proved undeveloped locations and so it’s much less than the total 976 locations that we have. So as we continue to grow our reserves, we will be able to continue to – as our cash flow continues to grow and we had larger drilling programs, you will see continued growth in the proved reserve base as more of those locations which would qualify to be proved could be booked under the SEC rules. On Slide 14, we recap the drilling program that’s on plan – that’s planned for this year and so this is – we still have the same plan that we had that we put out earlier with the first quarter results. Overall, we see this kind of sticking to this plan, but we are currently are looking at 2019 and anticipate kind of putting a budget in place in ‘19 within the next several months as we look ahead and see what we think commodity prices will be and what our cash flow will be. So the plans for 2019 are obviously to come up with the Haynesville drilling program and also develop some of our Eagle Ford acreage and do that all within the operating cash flow that we expect to generate in 2019. For this year and for the whole year our CapEx budget is still the same, it’s at $237 million and that would have us drilling 78 wells, but 24 wells met our interest. So 36 of those wells are operated Haynesville-Bossier wells, then there are 5 non-operated wells in those numbers. Four of the wells will be on our Eagle Ford property will be under our new joint venture with our partner there as we develop some of the undeveloped potential of that asset that we didn’t sell. And 33 of the projects are in the New Boston properties and most of those are to complete wells that have been drilled, but are not completed yet. The average lateral length of this year’s Haynesville program is 20% longer than last year. As – if you look at our – at the mix of wells that we are drilling this year, our program is mainly targeting the 10,000 foot laterals which is our highest return projects. We also have seven refracs budgeted as we look to kind of prove up the economics of re-fracking the old Haynesville wells. And $52 million of the budget relates to what will be spent on the Bakken properties to complete a lot of the uncompleted wells and to drill a handful of new wells and that’s the – those are the dollars that will be spent after they come into the company on August 14. So, I now turn it over to Dan to kind of give you an update of what our drilling results have been in the second quarter.

Thanks, Roland. You’ll see on Slide 15, this highlights our now 80,000 net acres in the Haynesville and mid-Bossier shale play across North Louisiana and East Texas. You will notice this number has increased since our last update and does reflect the additional 9,900 net acres we acquired with our recently announced Haynesville shale acquisition from Enduro Resource Partners. Over on Slide 16, you will see our 9 new wells that have been completed since our last call and these were represented by red callouts. All 9 wells were completed with our Gen 2 frac design using 3,800 pounds per foot. The average initial production rate of all 9 wells was 24 million cubic feet per day. Lena Crews 15-10 #1 well was drilled in the Haynesville with a 9,569 foot completed lateral. The initial production rate on this well was 34 million cubic feet per day. The Bagley 29-32 #1 well was drilled in the Haynesville with a 7,467 foot completed lateral and the initial production rate on this well was 26 million cubic feet per day. The BSMC LA 13-24 #1 was drilled to the Bossier formation with a 9,752 foot completed lateral and had an initial production rate of 16 million cubic feet per day. The Cook 21-28 HC #1 and #2 wells were both drilled to the Haynesville and the #1 well having a 9,407 foot completed lateral and the #2 well with a 8,733 foot completed lateral. The initial production rates were 26 million and 27 million cubic feet per day respectively. The Nissen 28-21 #1 and #2 wells were both drilled to the Haynesville, the #1 having a 9,486 foot completed lateral, the #2 well having a 9,468 foot completed lateral. The initial production rates on these wells were 27 million and 25 million cubic feet per day respectively. The Furrh #2H and #3H wells were both drilled to the Haynesville, the 2H having a 8,568 foot completed lateral and the 3H having a 8,283 foot completed lateral. The initial production rate on these wells, were 20 million and 21 million cubic feet per day respectively. And not to be minimized the green callout on this slide illustrates the strong results from the recently completed 4 non-operated wells that we participated in as part of the recent Enduro property acquisition. All 4 wells were drilled in Haynesville, had lateral lengths of approximately 9,700 foot and we are tested with initial production rates of 29 million to 33 million cubic feet per day. As of today, we are currently fracking 4 wells and flow testing additional 2 wells. Over on Slide 17, this is you have seen before and it shows the latest update to how our Haynesville and Bossier wells sufficient history that will perform against our base 7,500 foot type curve. The red curve represents the average of our 12 Gen 1 Haynesville wells that were completed in 2015 and early 2016. These wells continue to perform above our type curve. The purple curve represents the average of our now 24 Gen 2 Haynesville wells completed from late ‘16 through 2018 and these wells continue to perform our Gen 1 wells. The light blue curve represents the average of our 8 Gen 2 short lateral Haynesville wells and these are also outperforming our base 7,500 foot type curve. The green curve represents our four Bossier wells, which are also outperforming our base of 7,500 foot type curve and are also outperforming our average Gen 1 Haynesville wells over time. On Slide 18, this is an updated overview of our horizontal Haynesville and Bossier well inventory. The inventory includes the 112 new potential drilling locations associated with the recently closed Enduro property acquisition, of which 21 of these locations will be operated by us. At this time, our inventory now stands at 976 total locations, of which 582 are in the Haynesville and 394 locations on the Bossier, 728 of these locations were 75% of our total inventory, are our operated locations. Our average working interest across the entire inventory is roughly 74% with an average royalty burden of 80%. We are continuing for executing additional acreage trades to further enhance our inventory of long, long locations. And with that, I would now turn it back over to Jay.

Alright, Dan and thank you, Roland. In six days we will have the new Comstock enter the shareholder vote on Friday, so I think that’s really what we are looking forward to. If you look at Slide 19, we are going to summarize the new Comstock which will start on August 14. What has not changed is that our Haynesville-Bossier shale assets will continue as Dan just showed you to provide consistent higher return and low risk drilling opportunities in the future. We have an extensive acreage position that underpins our 976 locations in this prolific natural gas basin. The Bakken Shale oil weighted production contributed by Jerry Jones will provide future exposure to oil prices. This asset contribution represents a $620 million equity investment into the company which is transformational. We will reinvest a substantial cash flow generated by the Bakken properties to fund our drilling activities in the Haynesville and Eagle Ford. This will give us the platform. This is the new Comstock, the platform to generate substantial production growth all within our operating cash flow. The cornerstone of the new Comstock’s financial strategy is to drill within cash flow. The Bakken properties enabled us to ramp up our Haynesville drilling program to generate substantial growth without having to access external capital or increase our leverage. Pro forma, our leverage ratio was at 2.9x and we see achieving our corporate goal of driving this down to under 2x as we enter 2020. Another major component of our financial strategy is to maintain adequate liquidity within our capital structure. Our pro forma liquidity will be around $400 million as Ronald has explained. We target maintaining liquidity equal to our annual capital expenditures. The last part of our strategy is to reduce exposure to volatile oil and gas prices which we are able to do by hedging 50% to 60% of our anticipated next 12 months production. So for the rest of the call we will take questions from the analysts who follow the company. I will turn it over to the speaker.

Thank you. [Operator Instructions] Our first question comes from Ron Mills from Johnson Rice. Please go ahead.

Good morning Jay, maybe first question for Dan on the well results the two you had in East Texas, I am curious in terms of your expectations of those wells going into, I know East Texas is expected to be a little bit less prolific than North Louisiana, so could you frame up the performance of those versus North Louisiana and how you think about splitting the activity between East Texas and North Louisiana going forward?

Yes, Ron. So, we do expect a little bit less over in Texas, it’s obviously the Haynesville becomes a little bit more as you move to the west. So, we didn’t expect to see exactly the same numbers we had up in the Northern Caddo Parish, but we did have pipeline issues there. It started that limited us a little bit. And we also are going to drill those wells down a little bit lower like the same that we do our Bossier wells down in Southern DeSoto. There is little bit more sense to the drawdown and so we want to follow a little bit more of a choke back, a choke back routine on the wells that we do over in the [indiscernible].

Okay. And when you think about you inventory in East Texas versus Louisiana, is the focus really going to remain in – on the Louisiana side of the border?

I think what we will do, Ron we are going to take our best wells. We are going to look at where our gathering is. We are looking at look at where our rigs are. We are going to look at how many wells we can drill for a pad and that’s what our budget is going to be. We are going to try to get the most out of every dollar we put into ground.

Okay, great. And on the Enduro acquisition, particularly the operated piece that you really – you are in really nicely with your existing position, what’s the split in between the operated and non-operated and average working interest in the non-op, I am trying to get a sense especially if the other operators going to drill 4 additional wells like they just turned on?

Well, Ryan, a lot of the non-operated I think that the interest for areas that are active is around 28% working interest on the areas that we see drilling activity coming out from that generated by non-operators in excess to peak with the largest of those. And the operated is very high interest and obviously will put the units together there and determine the timing of that. So, we do anticipate some more projects, I think that are AFEd another 4 wells or so on the non-operated acreage by the end of the year down the activity that we see right now, but there is a lot of acreage there and we are going to have try to do some trades if we can potentially get shipped more than the operated side.

Okay. And then Roland you mentioned on the facility upgrade, it’s going to be completed by next week, so you will have that downtime through half of this quarter as well at a curiosity, should we – should the third quarter shut-ins look pretty similar to what they were in the second quarter or do you expect it to be a little bit different for some other reason?

Yes, the third quarter – it won’t be as low as the first quarter, because of you have had quite a bit of impact for July and half of August. So I think it would maybe a little bit less than the second quarter, but not as low as the first, yes.

I guess, I am trying to get a sense of that you had $19 million of shut-ins you had been running kind of 5 to 8, which is I think is your offset fracs and so that seems fairly normal, but from the plant or the facility itself, I think your gas volumes should be up sequentially because of your recent additions, but the shut-in impact, I am trying to get a sense, is it relative shut-in impact of the third quarter versus the second?

Yes. I think especially if you actually split the third quarter and the two parts that it’s really going to be reported in, because the company will change dramatically on August 14. So, I think you will see a very similar shut-in rate for that first half of the third quarter, then post the contribution of all that, then you will have the capacity to sell more gas there up in Caddo Parish.

Okay. Thanks for the clarification.

This is Dan. I would just echo what Roland said, our shut-in volumes are basically combination of pipeline filaments and shutting in for offset frac activity, a lot of that offset operators, not of frac activity. So we will see the pipeline curtailments basically go away by early next week. And then really looking going forward, you are just looking at shut-in volumes for offset frac activity. So, like you said, it won’t be as low as what it’s been in previous quarters, we should see quite as high as what we have seen in the second quarter.

Okay, thank you.

You know, Ron and my other comment would be, I mean, the wells we have drilled are quality, it’s an issue with the wells, it’s quality and if you have such quality, you do have to upgrade your gathering, so that’s a good problem that we have had another and now those wells will start producing, so I like the problems we have.

Agreed. Thank you.

Thank you. Our next question comes from Mike Kelly from Seaport Global. Please go ahead.

Hi, guys. Good morning. Jay, just a high-level one for you to start here in a few days, Jerry Jones can own 84% of the company. And I am just curious if we could expect to see any noticeable shifts in strategy or just philosophy versus kind of what you guys have really built the company on the past? Thanks.

Well, I think number one, he does not like that at all. He is risk-averse to debt and he loves the Haynesville-Bossier. I mean so I think those are the two key things. And I think the way I answer the question with Ron Mills earlier and that is where you are spending your money after the 15th of this month and that is every dollar that we can we are going to put in the very prospect that we have. Now, we have got partners in some areas, but our goal and that is to continue to de-lever the balance sheet, it’s to maximize every dollar that we spend. It is to the Enduro type acquisition. I think if there are others out there that you can pick up 26 million a day 288 Bcfe of reserves and you can pickup 30 plus locations. We will be looking at that, because we are a better company for that. I think it you will be a very disciplined approach. It will be really good if you won’t – we are not trying to use our borrowing base to grow, we will grow within our cash flow and these wells have been really good. So again this transformation is pretty miraculous. And the Bakken assets complement the old Comstock assets and the old Comstock drill sites complement the Bakken’s production. So you add them up and one and one equals a whole lot, it equals the new Comstock, so good question Mike.

Mike, I might add you said change of loss, I think the way it changes the company’s financial strength will be substantially enhanced as you can see the ability to buy like in Enduro or other bolt-on transactions without having to be excessively creative in the joint venture structure. I think that – so I think we will be able to capture more value from the bolt-on opportunities which we think there are several out there that fit very well with our asset base that can be bought at attractive values. We will be able to do that with a lot more financial strength now and not have to be so excessively creative like we have been able to create that that value in the past, so.

And the new Comstock Mike, it’s not created to be stagnant. It’s not created to just drill out your locations, it’s created to grow. And I think that’s the important part and we have already shown you even when we were recapitalizing the company with Jerry Jones, we did Enduro. Now that all the Southern financial recap will be behind this after the 14th as Roland said and I have black line accounting and we have the new Comstock, I think we will be really towards the Haynesville-Bossier area which again we were one of the first rated ever created value there back in ‘07, ‘08, that is our goal.

Great. I appreciate that. One more for me maybe just kind of ask a little bit more insight on the A&D landscape and there are more internal and neural type opportunities out there in your eyes?

Yes. Definitely there are especially as the Haynesville footprint has grown like it has, with our work up there in Caddo Parish, I think it’s opened up opportunities there that for smaller companies that really don’t have the resources to yet to develop that acreage to join up the Comstock and put that under our umbrella. And I think there are those bolt-on opportunities, they are there that don’t have to be gigantic expensive transactions but they can be very well valued plug-in to the transactions. We see that mark that – we see the landscape overall not just in the Haynesville, but really across most of the sectors is that really a buyers market now. Capital is hard to get, the public markets are not in love with the sector at all and private equity has also got – is also kind of live exposure to the sector, so we see it’s a very interesting window out there of the buyers market for maybe good quality properties. So I think that’s…

Mike, I think typically the fact that we are a public entity in the Haynesville-Bossier footprint that’s one thing that some don’t have out there. And I think we are the right size. So you put performance, you put lots of locations, you put lot of liquidity, you put our growth and again I used that word torque, I think we can really grow this thing so.

Great. Thanks, guys. Appreciate it.

Yes sir.

Thank you. Our next question comes from Gregg Brody from [indiscernible]. Please go ahead.

Good afternoon guys.

Hello.

So, it’s just you reiterated your gas production growth targets for this year and next, how does that change with the Antero acquisition if you doesn’t change and then I didn’t see any potential changes to your capital budget this year, is that something that we might see next quarter from the Antero acquisition or you are planning to do any development there this year?

Thanks. Greg, this is Roland. Yes, we see that it’s going to take us into the land work and they integrate that into our program. So, to the extent that we didn’t integrate any wells in there, where we just replace a well that we had budgeted, because we basically have looked at using – currently are using 3 rigs and we are adding a fourth rig in September. So, there won’t be additional CapEx. We are not adding another new activity, because of Enduro, so to the extent that it has a well drilled on it, it just would look like something else on inventory. And we didn’t change guidance, I mean I think that the Enduro additional production that brings, we will just add that comes into the company starting with the month of August, we will definitely assure that we beat our goals of having gas production growth over 30% and probably we probably could increase the target, but yes, we really want to get the companies combined to get all that done before we really start changing guidance. It’s not going to be – again, the materiality of it would be that 20 plus million a day that it adds starting in April we see – I mean, starting August at the end of the year. Other than that, we don’t see major changes to the numbers because of that acquisition.

Got it. But the Enduro production should theoretically decline from here is you are not adding any wells this year?

Right. Well, there is probably – there might be a few, but yes, there is probably not any significant new production to come on from Enduro this year, yes, I would say other than what’s starting with and then you are seeing some brand new production from the, which is fairly large percentage of its production. So, instead of using the exact rate, that’s why I have said about 20 million a day or 26 or so.

Got it. And then just one more for you, so you mentioned that the production curtailment was also a result of the offsetting frac, is that….

Yes. We always have offsetting frac activity. That’s why you see it. Not, we always said we have it like Ron Mills pointed out 5 million to 8 million a quarter typically is shut-in due to wells we have to shut-in for offset frac activity. There are certain other operators. So that’s a normal expected activity level. What was extraordinary this quarter was not being able having to curtail our production up in Caddo Parish and even some whatever those new wells over in Waskom area due to the facilities having to be upgraded to handle these new volume that have exceeded everybody’s expectations, especially in Caddo Parish. So, when the upgrades are finally finished and working properly, we won’t really – we will have a capacity there to complete the development of that acreage without another big disruption.

Got it. And just a follow on to that, so the fix to the pipeline was that just compression and is there – did you foresee any issues over the next year or two that I mean requires some additional shut-ins?

Yes. So, the upgrades were basically there is no compression involved, it’s basically treating dehydration and aiming treating for CO2. So like we said earlier as about early next week disposed to have basically full capacity for all the production. So, basically, going forward, we should see any really pipeline curtailment problems for our production of Caddo Parish.

That’s great. Thank you for the time guys.

Gregg, one other o comment, if you look at our footprint of acreage in the Haynesville-Bossier, there is always a company to the north southeast, west of any of our footprint that has a well acre to higher well production. So we are not booking on any of these plays. And that’s a good theme, because if you are the outlier, then you might have trouble. We are not the outlier on any of it. That’s why some of this was shut in for this trading, because there are so some many good wells in that area being drilled by either us or offset operators. So again I like the problems we have.

I appreciate that.

Thank you. Our next question comes from David Beard from Coker Palmer. Please go ahead.

Hi, good morning gentlemen.

Good morning.

Just issue and it does surround 2019, I think in one of the slides you kind of talked about a pro forma EBITDA number out there for next year with the combined companies, I don’t know if that – if you could update that if you really want to weight to get all of these moving parts in place relative to that?

Pro forma numbers are going to be that projected, that’s historical. Yes, I think we don’t have kind of audited final second quarter numbers yet for the Arkoma Williston properties. So I think we will be able to update that once that is complete. We didn’t want to do that with estimates. So, once we have the real results from the properties we are acquiring kind of completely audited and in great shape, which we will file in our 8-K subsequent of the transaction, if we could update our first quarter pro forma numbers to second quarter.

Yes, I was really pointing more towards 2019 not necessarily this year?

Yes, projections, yes. I think we have some general guidance how we get out effect and we have some general guidance out there for ‘19 but companies put together, we want to go and took a hard look at what’s the capital budget is going to be and for 2019, it’s going to be really governed by the cash flow the company can generate based on where our hedge positions are put in place. So, I think we want to get all those parts in place and get a new budget approved for ‘19 to kind of put out ‘19 kind of guidance, but we see generally a lot of growth obviously in the Haynesville and preliminarily if going to 5-rig program for ‘19 versus the 4 rigs will be ending this year, but again, if that doesn’t fit within cash flow we will kind of re-look at that as we now look at the total drill schedule for next year and that’s kind of where like an Enduro may come into play and those projects maybe in there and so we will look at the whole drill schedule and come up with a new, but we think it will be similar to what we guided to and have the potential to have substantial growth in gas production next year with a program that can be funded with the combined cash flow of our properties and the new Bakken properties.

Understood. Next shifting to the joint venture, any sort of updated thoughts now that you sort of have more projects and more cash flow how do they kind of fit in with that?

The joint venture with Arkoma that’s what you are talking about or the one with…

No, USG?

Yes, the joint venture with USG is pretty project specific. So, it’s on the acreage that they contributed, but we see that continuing, because we are going to develop out the acreage in Caddo Parish that they contributed and our interest now is shifted to 40% for the newer projects as we are underway. But as far as the other joint projects have together, it will be – those are definitely possible, but we will have to look at that we make joint acquisitions together that they contribute new acreage etcetera. Yes, we are not really looking to sell down a lot of interest in our core inventory at all or to accelerate and we don’t see the need to do that, but yes, we will continue to use that joint venture relationship to add kind of new activity, but I think it’s actually I see it kind of being right now set kind of where it is and we will have probably a two-rig program with them to continue to develop the acreage – the joint acreage that we have together.

Okay, thanks. And then lastly, just where you think the Bossier fits in relative to the new Comstock going forward?

Yes, we continue to want to put to allocate some capital to Bossier as we continue to de-risk it. I mean, I think it’s a different play. And I think the wells we have had good results in the 5 Bossier wells that we have drill to-date, they don’t have to higher IPs like the Haynesville, but if you just look at their performance, they do have a lower decline and so they are good steady producers. So I think again we are still trying to optimize kind of that Bossier completion and install it in the industries, especially in the southern Haynesville is very focused on the Bossier. So, I think it’s a big inventory there. I still see it as something that will be kind of maybe it’s 10% or so of our activity not much more than that until we really kind of continued to optimize our approach and how we drill and complete those wells. And again, the Haynesville wells are much more de-risked, proven and we felt like we are more ready to drill those and multi-pad units. In the Bossier, we still want to know try different projects in different parts of our acreage and continue to optimize our approach to that. So again, it’s other than wanting to continue to de-risk the acreage, there are lot of projects, Haynesville projects with strong economics, especially where they may have the lower royalty cost, etcetera that are in line first that would put push our Bossier development out several years.

Okay, great. Thanks for all the time and all the questions. Appreciate it.

Thank you. Our next question comes from David Epstein from Cowen. Please go ahead.

Hi, thanks. I missed a couple of minutes though I apologize if this was asked. Can you tell us what P&C CapEx per well is looking like and what we are seeing in terms of inflation nowadays? Thanks.

Hi, this is Dan. We basically seen with the slowdown in Permian a little bit, we have seen the softening in the frac market. We basically have seen our D&C come down in the last 6 to 9 months for D&C cost per well and it just depends on the lateral length that we are drilling and completing, but we have seen a fairly good decrease in our overall call since back at the first part of the year and it’s really been driven by basically softening in the frac market.

Dan, you might add, I guess between – really between what wells drilled in June and July there has been a pretty substantial reduction in our frac, our total cost per well which is….

Yes. We have dropped probably about 10% overall. It’s in the 15% overall. I mean, the frac calls us the driver of the total D&C cost and we have seen – the overall D&C is down. We have seen a little bit of that, get washed back just from the tariffs and the increase in steel prices, but overall we have seen a decrease in total cost, I would say, it’s at least 10% to 15%.

And I think that really kicks in though, we are starting with July, so you didn’t put these numbers to June probably don’t reflect it yet. So, but I think – because I think that’s where most of it, that big price reduction kind of hit right there starting with our July kind of projects?

Yes, it’s pretty competitive. We have had the different frac companies come in, in fact on a 10,000 foot lateral in a way. We have the savings of about a $140,000 per well for 10,000 foot lateral. So that’s a real number and that’s from a Tier 1 service company and they are bunch of them out there and they are competitive. So I think we will have some more surprises to the positive on that as the months go by.

So that’s all good news. Your CapEx budget and your – which also has a number of expected net wells attached to it right, so there is implied D&C per well in there. Is your CapEx budget sort of already, reflect all this good news or is it – or is there room to maybe increase the number of wells slightly?

Yes. I think the CapEx budget still has the earlier pricing in it from the earlier part of the year as far as what’s the rest of this year, but yes, as we absorbed those cost savings, yes, will be revising that somewhat. I think the activity level though is kind of driven by the rigs under contract. So, I don’t think – I think probably we under-spend that budget versus you add new activity.

And maybe the number of rigs, I mean it is important to an extent, but it’s how much of each well do you all, I mean, that’s more important and we will probably start drilling wells and we own 100% interest in now like we did in ‘15 and early ‘16.

Right, that’s a good point. Because if you look at – even if right now prior to closing the Arkoma transaction we are running 3 rigs, but 2 of them are mainly drilling wells that we owned a quarter of to half of, the other one is higher interest projects. So, the rig we had in September will be drilling higher interest projects. So, on a net rig basis, it’s probably pretty substantial. We are probably running only two net rigs maybe slightly less than that and maybe we will be closer to 3 net rigs as we add this extra rig.

And if you just look at operations, I mean you would rather run 2, 3, 4 rigs if you own 9% assets, twice that many, because it’s the same amount of work for every well you drill, no matter what interest you own. So, we will be more focused on it. Again, that’s the new Comstock, the new Comstock will drill within cash flow and we can focus on drilling our own wells.

Great. Thank you for the color.

Thank you. This concludes our Q&A session. At this time, I would like to turn the call back to the CEO, Jay Allison for closing remarks.

Number one, I would like to thank all of our partners and our JV partners, etcetera, we have the best orders in the world. I would also like to make comment that in a world of business, Jerry Jones is known to make money. And he has looked at us for almost 20 years and he made his initial wealth in the oil and gas sectors. We have got an oil and gas man backing an oil and gas company. Product is only 1.5 day from now. It’s a big day for us, which we have shareholder meeting in 10 a.m. We can get the vote then on the 14th which is this coming Tuesday, it’s final closing as Roland had mentioned. And when the sun comes up on 15, we have a new Comstock. It’s new accounting, new everything. We have the liquidity of around $400 million. We will have hedges 50% to 60% on gas and like Roland said, we will immediately start hedging our oil and the cornerstone of the new Comstock will be drilled within cash flow and drill your best wells that you can to keep your leverage down. I mean, we will start our leverage at 2.9 and we have said that our goal is to have leverage under 2x, but as we enter 2020 sometime. We do have an extensive area of inventory, I mean, our 976 locations. And again, that’s the company that the Haynesville would warrant back in February 2015. I want to take this second quarter call to thank all the shareholders, the bondholders, whether you are unsecured and now you are secured, our bank backers, the analyst, every one of you out there that have supported this conclusion, which no one knew what this conclusion would look like until maybe 6 weeks ago. And I want to especially thank Jerry Jones and all of his people for the equity investment of the $620 million, which truly transformed Comstock. We do have seasoned management that we have got Tier 1 area and now we hope to give you consistent growth within cash flow. So, it’s quite a journey and I am looking forward to the next conference call. Thank you.

Thank you, ladies and gentlemen for attending today’s conference. This concludes the program. You may all disconnect.