Comstock Resources Inc (CRK) 2018 Q2 法說會逐字稿

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'd like to turn call over to your host, to the CEO, Jay Allison. Please go ahead, sir.

All right. 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'm Jay Allison, Chief Executive officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Dan Harrison, Vice President 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 presentations 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 over to Slide 3, our 2018 second quarter summary. We expect to complete the contribution transaction through which Jerry Jones will contribute to his Bakken shale properties made a $620 million to the company for 84% of our common stock on August 14. We will use the cash flow from these properties, which is around $200 million to spud 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 outstanding debt with borrowings under the new bank credit facility with a $700 million borrowing base and $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've 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 undrilled locations. I'll 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 in 2 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 made 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 for contributing 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. We will use the proceeds from the notes offerings together with cash in the balance sheet and borrowings under the bank credit facility to fund a 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 undrilled wells. Net production from these wells in the first quarter was approximately 10,400 barrels of oil per day and 17 million cubic feet of natural gas per day. Our independent reserve engineers have estimated the proved reserves at 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 estate 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 include a 120 or 26.2 net producing natural gas wells, 49 or 14.7 net other wells are Haynesville wells. The final adjusted purchase price was $37 million, which included cost of 4 or 1.1 net recently completed the Haynesville shale wells incurred after the effective date of the sale of January 1, 2018. The Enduro properties are producing approximately 26 million cubic feet per day of natural gas and the estimated proved reserves of 288 Bcfe. We've 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 have Roland Burns go over the second quarter financial results. Roland?

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 on many of our operating cost items. Our lifting cost decreased 4%, despite the 19% higher production level and our depreciation, depletion and amortization per unit was down 12% due to our overall improved finding cost from the Haynesville shale program.

Our G&A cost this quarter came in at $7 million and was 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 an unrealized mark-to-market loss on our hedge position of $2.7 million. The noncash amortization of the large discounts recognized on the 2016 bond exchange of $12.2 million, which is included in 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 summarize the financial results for the first half of this year. For the first 6 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.

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% overall 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 noncash amortization and the discount recognized on the bond exchange of $23.2 million, the $400,000 of costs related to the unsuccessful tender offer and $35.4 million of loss on property sales, primarily related to the Eagle Ford sale. Without these items, the loss would have been $15.4 million for the first 6 months of this year or about $1.01 per share.

On Slide 9, we recap what our -- what production we had shut-in for the quarter. And as you've 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 on the wells that we've 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 of the overall lifting costs or gathering costs, which were $0.20; production taxes, which averaged $0.05; and then our remaining field level operating costs 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've summarized our hedged position that we have 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. The other half is in collars with $2.50 floor, with ceilings of $3.50 to -- ceilings of $3.30 to $3.50 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 debts. 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 an initial borrowing base of $700 million, and we've issued [$850 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 is 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'll fund a tender offer with proceeds, which will be released from escrow from the $850 million notes offering and it will also have borrowings under the credit facility and we'll use some of the cash on our balance sheet.

So after paying all the transaction costs, our pro forma cash would be about $37 million and we do 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 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. 27% of those volumes were developed and 90% were natural gas. The PV 10 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 Haynesville/Bossier reserves and 8% are in the Bakken shale just on a volume basis.

If you look on a value basis, the Bakken makes up 1/3 of the PV 10 value. The proved undeveloped locations in the reserve report were booked on a conservative drill within cash flow drilling program and are limited to only 5 years of drilling based on the SEC rules. So as such, the proved reserves that representing here include only 239 proved undeveloped locations, and so it's much less than the total of 976 locations that we have.

So as we continue to grow our reserves, we'll be able to continue to -- as our cash flow continues to grow, when we have larger drilling programs, you'll 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 the -- we still have the same plan that we had -- that we put our earlier with the first quarter results. And overall, we see it's kind of sticking to this plan. But we currently are looking at 2019 and anticipate kind of putting a budget in place for '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.

But for this year, for the whole year, our CapEx budget is still the same. It's at $237 million, and that would have us drilling 78 wells or 24 wells net to our interest. So 36 of those wells are operated Haynesville/Bossier wells then there are 5 non-operated wells in those numbers.

4 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 then 33 of the projects are in the new Bakken 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. If you look at our -- at the mix of wells that we're drilling this year, our program is mainly targeting the 10,000-foot laterals, which is our highest return projects. We also have 7 refracs budgeted as we look to kind of prove up the economics of refracking the old Haynesville wells. And $52 million of this -- 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 on what our drilling results have been in the second quarter.

Thanks, Roland. You'll see over Slide 15 this highlights our 80,000 -- 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 the last update and it 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'll see our 9 new wells that have been completed since our last call and these are represented by the red callouts. All 9 wells were completed with our Gen II 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 at 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 at 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, the #1 well having a 9,407-foot completed lateral and the #2 well with 8,733-foot completed lateral. 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 with the #1 having a 9,486-foot completed lateral and #2 well having a 9,468-foot completed lateral. 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. Initial production rates on these wells were 20 million and 21 million cubic feet per day, respectively.

And not to be minimized, the green callouts you see on this slide illustrate 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 to Haynesville, had lateral lengths of approximately 9,700-foot and were tested with initial production rates of 29 million to 33 million cubic feet per day. As of today, we're currently fracking 4 wells and have -- and are flow testing additional 2 wells.

Over on Slide 17, this is one you've seen before and it shows the latest update to how our Haynesville and Bossier wells, with sufficient history, are performing against our base 7,500-foot type curve. The red curve represents the average of our 12 Gen I 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 II Haynesville wells completed from late '16 through 2018. And these wells continue to outperform our Gen I wells. The light blue curve represents the average of our 8 Gen II short lateral Haynesville wells and these are also outperforming our base 7,500-foot type curve. The green curve represents our 4 Bossier wells, which are also outperforming our base 7,500-foot type curve and are also outperforming our average Gen I Haynesville wells over time.

On Slide 18, this is an updated overview of our horizontal Haynesville and Bossier drilling 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 are in the Bossier. 728 of these locations are, 75% of our total inventory, are operated locations. Our average working interest across the entire inventory is approximately 74%, with an average royalty burden of 80%. We are continuing towards executing additional acreage trades to further enhance our inventory of long lateral locations.

And with that, I'd now turn it back over to Jay.

All right, Dan. And thank you, Roland. You know in 6 days, we'll have the new Comstock after the shareholder vote on Friday. So I think, that's really what we're looking forward to.

If you look at Slide 19, we're going to summarize the new Comstock, which will start on August 14. What is not changed is that our Haynesville/Bossier shale assets will continue, as Dan just showed you, to provide consistent, high 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. His asset contribution represents a $620 million equity investment into the company, which is transformational. We will reinvest the substantial cash flow generated by the Bakken properties to fund our drilling activities in the Haynesville and Eagle Ford. This will give us a 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 enable 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 is 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 Roland 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 will do by hedging 50% to 60% of our anticipated next 12 months production.

So for the rest of the call, we'll take questions from the analysts, who follow the company. I will turn it over to the speaker.

(Operator Instructions) Our first question comes from Ron Mills from Johnson Rice.

Jay, maybe first question for Dan, on the well results, the 2 you had in East Texas, curious in terms of your expectations of those wells going into. And 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 as mostly the Haynesville becomes a little bit more clayey 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 but limited us a little bit. And we also are going to choke those wells down a little bit more like the same that we do our Bossier wells down in Southern DeSoto. It makes a little bit more sense to drill down and so we're going to follow a little bit more of a choke back routine on the wells like we do over in the Waskom area.

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

I think what we do, Ron, we're going to take our best wells and we're going to look at where our gathering is, we're looking where our rigs are, we're going to look at how many wells we can drill per pad and that's what our budget is going to be. We're 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 fits really -- in really nicely with your existing position. What's the split in between the operated and nonoperated? And average working interest in the non-op, I'm trying to get a sense especially if the other operators going to drill 4 additional wells like they just turned on?

Well, Ron, a lot of the nonoperated, I think, that the interest per area that are active is around 28% working interest kind of areas that we see drilling activity coming up from -- that's generated by nonoperators and like Chesapeake was the largest of those. And the operated is very high interest. So and obviously we'll look at the units together there and determine the timing of that. So we do anticipate some more projects. I think, they've AFE-ed another, I think, 4 wells or so on the nonoperated acreage by the end of the year but some of the activity what we see right now, but there are -- there's a lot of acreage there and we're going to also try to do some trades if we can potentially get shifted more to 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. Out of 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, well, it will be -- it won't be as low as the first quarter because of the -- we've had quite a bit of impact for July and half of August. So I think, it'll be a little -- maybe a little less than the second quarter, but not as low as the first half.

But I guess what I'm just trying -- I'm trying to get a sense of that you had 19 million of shut-ins, you had been kind of running 5 to 8, which is, I think, is for 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'm trying to figure since it's a relative shut-in impact of the third quarter versus the second?

Yes. And I think it's mostly -- if you actually split the third quarter into the 2 parts that it's really going to be reported in because the company will change dramatically on August 14. So I think you'll see a very similar shut-in rate for that first half of the -- first -- the third quarter. But then, post the contribution and all that, then you'll have the capacity to sell more gas there up in Caddo Parish. Do you want to answer, Dan?

Yes. Thanks Ronald. And I would just echo what Roland said. While our shut-in volumes are basically combination of pipeline curtailments and shutting in for offset frac activity. A lot of that will be offset operators not all frac activities. So we'll see the pipeline curtailments basically go away by early next week and then really going forward, you're just looking at shut-in volumes for offset frac activities. So like you said, it won't be as low as what it's been in previous quarters. We should not see anything quite as high as what we've seen in the second quarter.

Ron, and my other comment would be, I mean, the wells we have drilled are quality, it's not 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've had. And now those wells will start producing. So I like the problem we have.

Our next question comes from Mike Kelly from Seaport Global.

Jay, just a high-level one for you to start here. In a few days now, Jerry Jones is going to own 84% of the company. And I'm 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?

Well, I think, #1, he does not like debt at all. He is risk adverse to debt. And he loves the Haynesville/Bossier. I mean, so, I think those are the 2 key things and I think the way I answer the question with Ron Mills earlier and that is where are you spending your money after the 15th of this month. And that is every dollar that we can, we're going to put in the very best prospect that we have. Now we've got partners in some areas. But our goal and that is it's to continue to delever the balance sheet. It's to maximize every dollar that we spend. It is to get 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 if you could pick up 30-plus locations, we'll be looking at that because we're a better company for that. I think that, that -- I think it'll be a very disciplined approach. It'll be really good because we won't -- we're not trying to use our borrowing base to grow. We'll 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.

Yes. Mike, I might add. You said change of clause. I think the biggest change is the company's financial strength will be substantially enhanced as you could see, ability to buy like an Enduro or other bolt-on transactions without having to be excessively creative within the joint venture structure. I think that -- so I think, we'll be able to capture more value from the bolt-on opportunities, which we think there are several out there that, that fit very well with our asset base that can be bought at attractive values. And we'll be able to do that with a lot more financial strength now and not have to be so excessively creative like we've been to be able to create that value in the past. So but...

Well, 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've already shown you, even when we were recapitalizing the company with Jerry Jones, we did Enduro. Now that all is sheltered, general financial recap will be behind us, after the 14th as Roland said, and I have BlackLine accounting and we have the new Comstock, I think we'll be really torqued toward the Haynesville/Bossier area, which again we were one of the first 3 to ever create value there back in '07, '08. That's, that's, that is our goal.

Great. Appreciate that. One more for me. Maybe just can I ask a little bit more insight on the A&D landscape. And if there are more Enduro-type opportunities out there in your eyes?

Yes.

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 develop that acreage to join up with Comstock and put that under our umbrella. And I think there are those bolt-on opportunities that are there that don't have to be gigantic, expensive transactions, but that can be very well-valued, kind of plug into transactions. We see the mark that -- we see the landscape overall not just in the Haynesville, but really across most of the sectors, it's 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 is also got -- it's also got a lot of exposure to the sector. So we see it's a very interesting window out there of a buyers' market for may be good quality properties. So I mean, I think that's...

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

Our next question comes from Gregg Brody from Bank of America Merrill Lynch

So should we reiterate your gas production growth targets for this year and next, how does that change with the Enduro acquisition if you or does it 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 Enduro acquisition? Or are you not going to do any development there this year?

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

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

Well, there is probably a -- there might be a few -- yes, there are probably not any significant new production coming out from Enduro this year, yes, I would say, starting with and then you'll see some brand-new production from the -- which is fairly large percentage of its production. We said using the exact rate that's why I said about 20 million a day so versus 26 or so.

Got it. And then just one more for you. So you mentioned that, that 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's not -- we always have, we have it. Like Ron Mills pointed out 5 million to 8 million a quarter typically shut-in due to wells we have to shut-in for offset frac activity either ours or with other operators. So that's a normal expected activity level. What was extraordinary this quarter was not to be enabled -- having to curtail our production up in Caddo Parish and even somewhat over those new wells over in the Waskom area do see -- the facilities having to be upgraded to handle these new volumes that have exceeded the revised expectations, especially in Caddo Parish. When the upgrades are finally finished and working properly, we won't really -- we'll have a lot of that 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 -- do you foresee any issues over the next year or 2 that may require some additional shut-ins?

(inaudible)

So the upgrades were basically, there's no compression involved. It's basically treating, which is dehydration and aim and treating for CO2. So like we said earlier, as about early next week, we expect to have basically full capacity for all the production. So basically going forward, we shouldn't see any really pipeline curtailment problems for our production up in Caddo Parish.

That's fair.

Gregg, one other comment. If you look at our footprint of acreage in the Haynesville/Bossier, there is always a company to the north, south, east or west of any of our footprint that has a well equal to our well production, so we are not booking on any of these plays. And that's a good thing because if you are the outlier, then you might have trouble. We're not the outlier on any of it. That's why some of those were shut-in for this treating because there are so many good wells in that area being drilled by other offset operators. So again, I like the problems we have.

Our next question comes from David Beard from Coker Palmer.

Just a issue and it does surround 2019. I think in one of the slides, you kind of talked of 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 as we really want to wait until we get all of these moving parts in place relative to that?

Well, the -- yes, pro forma numbers are going to be not projected, but historical. Yes, I think, the -- I think we don't have kind of audited final second quarter numbers yet for the Arkoma, Williston properties. So I think we'll 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're acquiring kind of completely audited and in great shape, which will fall in our 8-K subsequent of the transaction, then we could -- yes, we could upgrade -- we could update our first quarter pro forma numbers to second quarter.

Yes. As you're looking to reporting more towards '19, not necessarily this year?

Yes. Projections, yes. Yes, I know -- yes, I think, it's a -- we have some general guidance out there for '19, but as the new 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 could generate based on where our hedge positions are put in place. So there is a -- 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 our '19 kind of guidance. But we see generally a lot of growth obviously in the Haynesville and preliminarily if I'll go into a 5-rig program for '19 versus the 4 rigs we'll be ending this year with. But again, if that doesn't fit within cash flow, we will kind of relook at that as we now look at the total drill schedule for next year. That's kind of where like an Enduro may come into play and those projects may be in there. And so we'll look at the whole drill schedule and come up with a new budget. But we think it'll be similar to what we've 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 just shifting to the joint venture. Just any sort of updated thoughts now that you've sort of have more projects and more cash flow, how do they kind of fit in with that?

The joint venture with Arkoma, is that the one you're talking about? Or the one with...

No. The USG, USG.

USG. Yes, the joint venture with USG, it's pretty project specific. So it's on the acreage that they contributed. But we see that continuing because we're going to develop out the acreage in Caddo Parish that they contributed and our interest now has shifted to 40% for the newer projects as we earned our way out so. But as far as other joint projects out together, they will be -- those are definitely possible, but we'll have to look at do we make joint acquisitions together, do they contribute new acreage, et cetera. Yes, we're 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're continuing to use that joint venture relationship to add kind of new activity. But I think it's -- I'd see it kind of being right now set kind of where it is. And we'll have probably a 2-rig program with them to continue to develop the acreage -- the joint acreage that we have together.

Okay. And then lastly, just where do 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 the Bossier as we continue to de-risk it. I mean, I think it's a different play. And I think, the wells, we've had good results in the 5 Bossier wells that we've drilled. To date, they don't have the higher IPs like the Haynesville, but if you look -- if you just look at their performance, they do have a lower decline and so they're good, steady producers. So I think, again, we are -- we're still trying to optimize kind of that, that Bossier completion. And install it in the industry's, especially in the Southern Haynesville is very focused on the Bossier. So I think, it's a big inventory there. I still see something then will be kind of a -- maybe it's 10% or so of our activity, not much more than that until we really kind of continue to optimize our approach and how we drill and complete those wells. Again, the Haynesville wells are much more derisked, proven and we feel like we're more ready to opt -- to drill those in multi-pad units. In the Bossier, we still want to 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 costs, et cetera that are in line first that, that would push our Bossier development out several years.

Our next question comes from David Epstein from Cowen.

I missed a couple of minutes, so I apologize if this was asked. Can you tell us what a D&C CapEx per well is looking like? And what we're seeing in terms of inflation nowadays?

David, this is Dan. I'll -- we've basically seen with the slowdown in the (inaudible) a little bit, we've seen a softening in the frac market. We basically have seen our D&C costs come down in the last 6 to 9 months. Of course, D&C cost per well, it just depends on the lateral length that we're drilling and completing. But we've seen a fairly good decrease in our overall costs since back in the first part of the year and has really been driven by basically the softening in the frac market.

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

Yes. We've dropped probably about 10%, overall, 10% to 15% overall. I mean, the frac cost is the driver of the total D&C cost. And we've seen a -- the overall D&C is down. We've seen a little bit of that get washed back just from the tariffs and the increase in steel prices. But overall, we've seen a nice decrease in total costs. I'd say it's, at least, 10%, 10% to 15%.

And I think that really kicks into more starting with July. So these numbers through June probably don't reflect it yet. But I think as we -- because I think that's where most of that big price reduction kind of hit right there starting with our July kind of projects so.

Yes. It's pretty competitive. We've had the different frac companies come in. And in fact, on a 10,000-foot lateral, we have a savings of about $1,040,000 per well for a 10,000-foot lateral. So that, that's a real number and that's from a Tier 1 service company and they're bunch of them out there and they're competitive. So I think, we'll have some more surprises to the positive on that as the months go by.

So your -- 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's 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 from earlier part of the year as far as what's the rest of this year. Yes, as we absorb those cost savings, we'll be revising that somewhat. I think the activity level there was kind of driven by the rigs under contract. So I don't think we think -- probably, we understand the budget versus additional new activity.

Remember the number of rigs, I mean it is important to an extent, but it's how much of each well do you own, that's, that's more important. And we'll probably start drilling wells that we own more of, like we did in '15 and early '16.

Right. That's a good point because if you look at the -- even 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. And the other one is a higher interest project. So then the rig we add in September will be drilling higher interest projects. So on a net rig basis, it's probably pretty substantial. We're probably running only 2 net rigs, maybe a rig slightly less than that. And maybe we'll be closer to 3 net rigs as we add this extra rig.

And if you just look at operations, I mean, you'd rather run 2 or 3, 4 rigs that you own 100% than twice as many because it's the same amount of work for every well you drill no matter what interest you own in that. So we'll be more focused on that. Again, that's the new Comstock. The new Comstock, we'll drill within cash flow and we can focus on drilling our own wells.

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

I would like -- #1, I would like to thank all of our partners and our JV partners, et cetera. We have the best partners in the world. I'd also like to make a comment that, in the world of business, Jerry Jones is known to make money. And he's looked at us for almost 20 years and he made his initial wealth in the oil and gas sector. So we've got anoil and gas man backing an oil and gas company. Friday is only 1.5 days from now. It's a big day for us, which we have our shareholder meeting in 10:00 a.m. We can get the vote. Then on the 14th, which is this coming Tuesday, is final closing as Roland had mentioned. And when the sun comes up on the 15th, we have a new Comstock. It's new accounting, new everything. We have liquidity of around $400 million, we'll have hedges of 50% to 60% on gas. And like Roland said, we'll immediately start hedging our oil. And the cornerstone of the new Comstock will be drill within cash flow and drill your best wells that you can, keep your leverage down. I mean, we'll start our leverage at 2.9 and we said that our goal is to have leverage under 2x by -- as we enter 2020 some time. We do have an extensive area of inventory, I mean, our 976 locations, and again, we bet the company that the Haynesville would work back in February 2015. I want to take this second quarter call to thank all the shareholders, the bondholders whether you're unsecured or now you're secured, our bank backers, the analysts, 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 expressly 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 and we've got Tier 1 area. And now, we hope to give you consistent growth within cash flow. So quite a journey, and I'm 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. Good day.