Comstock Resources, Inc. (CRK) Q2 2020 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by and welcome to the Second Quarter 2020 Comstock Resources Incorporated Earnings Conference Call. [Operator Instructions] Now it’s my pleasure to turn the call to Jay Allison, Chairman and Chief Executive Officer. Please go ahead.

Thank you. Everyone that’s on the call, welcome to the Comstock Resources second quarter 2020 financial and operating results conference call. You can view a slide presentation during our act for this call by going to our website at www.comstockresources.com and downloading the quarterly result presentation. There, you’ll find a presentation titled Second Quarter 2020 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer; and Ron Mills, our VP of Finance and Investor Relations. If you go to Slide 2, it’s a disclaimer. 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 and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Before we get to Slide 3 I’ll make some comments. First of all, it’s a privilege to be able to talk to everybody. When each of you on this call this morning have an inbound call to hear from someone that has proven to take and create great wealth, you take that call and listen if you’re wise. Two and half years ago, Comstock Resources received a phone call from Jerry Jones and his family, which is why we as the Comstock management can report the quarterly results that we have today. Every train has a conductor and ours is Jerry Jones. He believed in natural gas in America. He believed that the Haynesville-Bossier shale in the United States was a Tier 1 natural gas play, and he put his $1 billion into Comstock because the Haynesville-Bossier has close proximity to the Gulf of Mexico, geological predictability, availability above midstream pipelines and proven historic well results. The second quarter 2020 was the stressed test quarter for the energy sector and it revealed weaknesses that all of us don’t ever look forward to seeing. But the vision set forward 2.5 years ago is coming to fruition as shown in this quarterly report that Comstock has a best-in-class low-cost structure with our margins in the Tier 1 area for natural gas in America. Without the Jones’ commitment, we would not have had the second-quarter results that we will give you because we would not have been able to do the transactions that we’ll report to you that we executed it all during the valve last quarter. We commit to you, the owners of this company, who own either equity or debt of Comstock that we will continue to make wise decisions on how to spend your money. The second quarter of 2020 may go down as one of the most difficult 90 days in the history of oil and gas. Yet during that 90 days, we were laser-focused on enhancing our financial strength. In May, we executed on an underwritten equity offering that gave us the financial ability to redeem the $210 million series a convertible preferred stock issued that we entered into as a part of the Covey Park acquisition. Then in June, we issued $500 million in a senior notes offering that were used to repay borrowings under our revolving credit facility that greatly improved our financial liquidity as Roland will report on. We as a company, that’s all 207 with us, the Board of Directors say thank you to the buyers of the equity and to the buyers of the bonds for trusting Comstock’s management to continue to deliver industry-leading low cost well economics. Your support during trying times in the oil and gas industry is greatly appreciated. We commit to you our financial backers of equity stakeholders that we will continue to focus on free cash flow generation over growth, focus on paying down our debt and shrinking our balance sheet and managing Comstock through the current low oil and natural gas price environment, with our best-in-class cost structure, leading margins and the depth of drilling inventory. We’re very well-positioned for the future and in fact, we’re eager to see what unfolds over the next 18 months because we see natural gas fundamental strengthening during that window of time. If you go to Slide 3, operationally the second quarter, was a fairly quiet quarter for us as we released our completion crews in April and we reduced our operated drilling rigs down to four. As low natural gas prices have continued following the warm winter we had planned for the lower activity in the quarter to prioritize free cash flow generation. We were very busy in the second quarter working to enhance our financial strength. The current volatile and uncertain environment we had with this COVID-19 pandemic, we were able to complete the first upstream common equity offering since 2018 larger than $50 million. The offering was also the first natural gas common equity offering since 2016. The offering allowed us to redeem our Series A convertible preferred stock at its face value of $210 million and avoid the potential dilution associated with this conversion. We follow that offering up with a $500 million senior notes offering to pay down borrowings on our bank credit facility. We reduced our outstanding bank borrowings from 89% of availability to 57%. By freeing up the bank credit facility, we increased our financial liquidity from $116 million at the end of the first quarter to $612 million currently. We further de-risked our business plan by increasing our 2021 hedge position by 182% during the second quarter, taking advantage of the improvement of the natural gas futures in 2021. On the operations front, we are capturing a reduced drilling and completion costs which Dan Harrison will talk about momentarily. Our second quarter drilling and completion costs for lateral foot are down 26% from second quarter 2019 cost. We expect well costs to decline further in the second half of the year as Dan will go over. We deferred our completion activity in the quarter to better align new production with anticipated strong natural gas prices in late 2020 and 2021. Despite the very low oil and natural gas prices we had in the second quarter, we still generated $36 million in free cash flow, bringing our total free cash flow in 2020 to date to $51 million. The low oil and gas prices did limit the profits we generated in the quarter. Our oil and gas lease sales and floating hedges were $233 million, that is 79% higher than sales in the second quarter of 2019. Our adjusted EBITDAX came in at $162 million, which was 74% higher than 2019. Operating cash flow was $117 million or $0.53 per share and was 77% higher than 2019. We did manage to have adjusted net income of $1.7 million or $0.01 per share for the quarter. If you go over to Slide 4. On Slide 4, we recap the equity and senior notes offering to be completed in the second quarter. In May we issued 41,325,000 shares and an underwritten equity offering, which was priced at $5 per share. We used the proceeds from the offering, along with $13 million of cash from the balance sheet to redeem the $210 million Series A convertible preferred stock at its face value. The Series A Convertible Preferred stock was convertible into 52.5 million shares beginning on July 16, 2020. The offering was accretive to the company, as we saved the company 11,175,000 shares that would have been issued had the preferred stock converted. The redemption saved us $21 million per year by eliminating the 10% dividend we were paying. In April and May, we exchanged $5.6 billion of our 7.5% senior notes due 2025 with certain holders for 767 and 96 newly issued shares of common stock. The exchange was done at market values above Securities. Effectively we issued the shares and the exchange at $7.30 per share. In June, we used proceeds from a $500 million senior notes offering to repay $441 million in borrowings under our revolving credit facility. The offering addressed our need to improve our financial liquidity. We use the bank credit facility heavily when we acquired Covey Park last July and we had intended to term out a portion of the borrowings. The tax financial liquidity was a primary reason for our credit rating that was downgraded in March by two of the agencies. The completion of the successful note offering led to an upgrade to our ratings by both Moody’s and S&P. I will now have Roland Burns summarize our financial results for the quarter. Thank you. Roland?

All right. Thanks, Jay. On Slide 5 we combined Comstock and Covey Park’s production from the Haynesville-Bossier since 2016. In the second quarter of 2020 production from our Haynesville-Bossier wells was 1.2 billion cubic feet per day and was 9% higher than the 1.1 billion cubic feet per day that Comstock and Covey Park produced in the second quarter of 2019. Low completion activity in the quarter caused production to decline slightly from the first quarter. We only had 5.7 net wells turned to sales during the second quarter. Given the continued weakness in gas prices since our last conference call, we’ve adjusted our completion schedule to allow us to continue to generate free cash flow despite low gas prices. While we still plan to complete a similar number of wells as before, the timing of returning the wells to sales has moved to later in the year in order to align more of the new production to the winter months when we expect natural gas prices to improve. As a result, we expect our third quarter production to decline a little further. We did add back two frac crews at the beginning of the third quarter and we plan to add a third frac crew later this year. We plan to turn 25 net wells to sales in the last six months of this year. Much of the new production from these wells will be on late this year setting this up for a strong exit rate and for some growth in 2021 but not in time to show growth in the third quarter. Slide 6 recaps the production we had shut-in for the quarter, principally for offset frac activity. Our non-operated oil production experienced substantial curtailments in the second quarter. We had 23% of our oil production curtailed or shut-in in the second quarter due to the very low oil prices. 4% of our natural gas production was also shut-in in the second quarter as compared to 5% in the first quarter of this year. Given our completion activity was low in the quarter, we expected the shut-in percentage to be closer to 2% to 3% in the second quarter, but given the significant amount of offset operator completion activity the shut-in activity came in at 4%. On slide 7, we cover our hedging program. During the first six months of 2020, we had 49% of our gas volumes hedged, which increased our realized gas price to $1.96 per Mcf from the $1.59 per Mcf we received from selling our production. We also had 90% of our oil volumes hedged and that increased our realized oil price to $42.59 per barrel versus the $31.72 per barrel that we actually received. Our realized hedge gains, totaled $98.7 million in the first six months of this year. With improvement in futures natural gas prices that we saw in the second quarter, we have added substantially to our hedge book. Since we last reported earnings, we’ve added 10 million cubic feet a day of natural gas swaps for the third quarter of this year and another 20 million of additional swaps for the fourth quarter. Then we’ve also added 25 million cubic feet of natural gas collars in the fourth quarter of this year, but most substantially we ended at 128 million cubic feet of natural gas collars in 2021 which protect us at an average floor price of $2.47 to give us exposure to the higher prices that we are expecting for next year. For the rest of 2020, we have 608 million cubic feet of our gas hedged in about 2,892 barrels of our oil hedged. The weighted average floor price of our remaining 2020 gas hedges is $2.61 per Mcf. For 2021, we now have hedges covering 668 million cubic feet of our expected 2021 gas production and the weighted average floor protection price for those hedges is $2.51. Our 2021 when gas hedged increases to 164 million cubic feet per day at an average floor price of $2.51 if certain swaptions are exercised in the fourth quarter of this year. We are targeting to have 55% to 70% of our anticipated 2021 production hedged. On Slide 8, we summarize our financial results for the second quarter of this year. Our production for the second quarter totaled 119 Bcfe including 360,000 barrels of oil. This is 163% higher than our production in the second quarter of last year. Our oil and gas sales including realized hedging gains were $233 million, which was 39% higher than 2019. Oil prices in the quarter averaged $37.89 per barrel and our gas prices average $1.88 per Mcf, including our hedging. Our natural gas price realization was down 18% offsetting some of the substantial production growth we had in the quarter. Adjusted EBITDAX came in at $162.1 million, which was 74% higher than the second quarter of 2019. Operating cash flow was $117.5 million, which was 77% higher. We did report a net loss of $60 million for the quarter or $0.29 per share. But that loss was mainly attributable to $65.6 million unrealized loss from the mark-to-market of our hedge positions and that change in the value of our hedge positions was mostly driven by the higher future prices for natural gas that we’ve seen since the March 31 balance sheet. Adjusted net income excluding that mark-to-mark hedging loss and the uncertain other unusual items was $1.7 billion or 0.01 per diluted share for the quarter. On Slide 9, we summarize our financial results for the first half of this year. Production for the first six months was 244 Bcfe including 814,000 barrels of oil. That is 194% higher than production for the first half of 2019. Oil and gas sales including realized hedging gains were $504 million or 92% higher than the same period in 2019. Oil prices averaged $42.59 per barrel and gas prices averaged $1.96 per Mcf, including hedging gains. Overall, our natural gas price realization was down 23% in 2020 versus 2019. Adjusted EBITDAX came in at $364 million or 91% higher than 2019 and operating cash flow was $273 million, which was 100% higher than 2019. We reported a net loss of $30 million for the first six months of 2020 or $0.15 per share. But again that was mainly due to the unrealized hedging loss from the second quarter. So excluding that, the unrealized hedging loss from the mark-to-market in other unusual items, the net income for the first half of the year was $28 million or $0.14 per share. On Slide 10, we detail our operating cost per Mcfe. Our operating cost averaged $0.54 in the second quarter as compared to the first quarter rate of $0.50. Gathering costs were $0.22 per Mcfe. Production taxes averaged $0.05 and field-level costs were $0.27. The taxes in the field level cost in the second quarter did include some prior period [indiscernible] and franchise tax adjustments that we recorded in the second quarter. On Slide 11, we detail our corporate overhead costs per Mcfe. Our cash G&A cost per Mcfe averaged $0.06 in the second quarter, which is exactly unchanged from what we had in the first quarter. Slide 12, we show our depreciation, depletion and amortization per Mcfe produced. That averaged $0.87 in the second quarter, which was 1% lower than the $0.88 that we had in the first quarter. On Slide 13, we recap our second quarter and first six months of 2020 capital expenditures. We spent $75 million on development activities in the second quarter of which $61 million was related to our operated Haynesville shale properties. For the first six months of this year, we spent $205 million including $165 million spent on our operated Haynesville Shale program. We drilled 26 or 20.1 net operated horizontal Haynesville wells so far this year. We also completed 15 or 9.6 net wells that we drilled in 2019. We spent about $40 million on non-operated or other activities so far this year. We generated operating cash flow of $233 million in the first six months of this year resulting in free cash flow of $51 million after we pay the dividend on the preferred shares. We continue to remain very responsive to the changing natural gas prices and remain focused on generating significant free cash flow. After dropping our operated rig count to four rigs in April, which was down from six in January, we’ve added back a fifth operated rig this week and we plan to add a sixth rig by the end of the year. We expect to spend approximately $400 million to $440 million this year to drill 67 or 42.8 net Haynesville wells and to turn 79 or 42.3 net Haynesville wells to sales. At the end of this year, we expect to have 17 or 15.3 net drilled uncompleted wells to carry over into 2021 and we also think we’ll be in various stages of drilling on 6 or 5.2 net operated wells at the end of the year. We remain focused on generating significant free cash flow as we look ahead in planning our capital expenditure activity and we’re targeting to have $150 million to $200 million of annual free cash flow as we set our drilling and completion activity for 2021. Slide 14 shows our balance sheet at the end of the second quarter. During the second quarter, as Jay said we were very active in the capital markets issuing 41.3 million shares of common stock to redeem the Series A preferred stock and issuing $500 million of new unsecured notes to term out a portion of the borrowings outstanding that are our credit facility. We also completed some debt for equity exchanges totaling $5.6 million in exchange for 767 and 96 newly issued common shares. We currently have $800 million drawn on our revolving credit facility and we expect to pay it down further with the free cash flow we’re generating for the rest of 2021 and what we’ll generate in 2020 what free cash flow we’ll have for the rest of this year and then what we will generate in 2021. With a quarter ending cash position of $12 million our current liquidity now stands at $612 million. We have just under $2 billion of senior notes outstanding, comprised of $619 million of the 7.5% senior notes due in 2025 and then $1.35 billion of our non and three-quarters senior notes due in 2026. With no debt maturities until 2024 and no senior note maturities until 2025, our current leverage ratio remains below, our covenant ratio of 4x so we’re very well positioned to continue to weather the current low oil and gas price environment. I’ll now turn it over to Dan to cover our second quarter drilling results in more detail.

Okay. Thanks, Roland. Over on Slide 15 you’re going to see the outline of the current acreage position. So we’re now standing at 305,000 net acres. There have been no material changes in our acreage position since we had our last call. We control the majority of the acreage. We’ve got a 92% operating position and we have an average working interest on the acreage of 80%. We currently have 2,007 net future drilling locations identified on the acreage with 95% of the acreage currently held by production. As a result of releasing our frac crews in early April we’ve not turned any additional wells to sales since the time of our last call so our well count still stands at 237 gross wells turned to sales since we re-entered the play in 2015. We’re currently running four rigs and we’re in the process of moving in a fifth rig this week. We also plan to add a sixth rig sometime before the year-end. Due to the frac holiday, this started in early April, our operated DUC well count increased to a maximum to 20 wells by the end of the second quarter. We currently have 16 operated DUCs at this time. We put two frac crews back to work at the end of June and we plan to add a third crew within the next couple of months as we prepare to drill down a number of DUCs and take advantage of the anticipated higher gas prices heading into the fall. Over on Slide 16. This is an updated breakdown of our Haynesville-Bossier drilling inventory at the end of the second quarter. Our total gross operated inventory currently stands at 2,520 locations with our net operated inventory at 1,849 locations. This represents an average of 73% working interest on the remaining operated inventory. In addition to the operated inventory, we also have 1,310 gross non-operated locations with our net non-operated inventory at 158 wells, which represents an average 12% working interest on the remaining non-operated inventory. As for the gross operated inventory, we currently have 538 short laterals, 1,005 medium laterals and 977 long laterals. Our gross operated inventory actually increased by approximately 6% in the second quarter and this was primarily due to closing on a few key trades that we’ve actually had in the works for some time now. Regarding the different pay ventures, 56% of our gross operated locations are located in the Haynesville and the remaining 44% of the locations are located in the Bossier. This inventory provides the company with over 30 years of drilling locations based on our forecasted activity levels for the near term. On Slide 17. This is a chart which illustrates the progress we continue to make driving down our D&C cost. These results track only our medium to long laterals which have lateral lengths of greater than 6,000ft. Obviously costs continue to trend down in the second quarter with three of our lowest all-in D&C costs to date at $1,028 per feet. This reflects the D&C costs on the seven long lateral wells that returned to sales in the second quarter, all in the month of April before we released our frac crews. This cost is 26% lower than the same quarter a year ago and represents an 8% cost reduction from the previous quarter. The main drivers, continue to be the increased completion efficiencies and the lower service cost associated with the historically low industry activity levels. We are continuing to pump smaller modified frac design that we started up in early in the year. This is primarily on our infill and co-developed locations and this has also been a factor in our lower well costs. As stated on our last call, we’re maintaining a near-term goal of reducing our D&C costs down to $1,000 per foot and we feel confident we’re going to be able to hold these costs at this level in the current service cost environment. Our goal is still to deliver the highest return and create the most value we can on the capital that’s being deployed That summarizes the operations. I’m going to turn it back over to Jay for some final comments.

Thank you, Dan. Thank you, Roland. I’ll go over the outlook for everybody on the call, turn it over for some guidance from Ron and we’ll open it up to questions. So if you go to 18, really, I’d like to direct you to Slide 18 where we summarize our outlook for the rest of this year. This year we’re primarily focused on free cash flow generation as we stated over and over and managing the company to the current low oil and natural gas price environment. While current natural gas prices remain relatively low, the outlook for natural gas has improved substantially for late 2020 and 2021 driven by our expectations for significant declines in natural gas supply in 2020 and 2021 due to a continued reduction in natural gas-directed drilling and completion activities and less associated gas production for related activities in oil basins, resulting from the collapse of oil prices. The strength we have is our industry-leading low-cost structure and well economics. With our industry-leading low cost structure, our Haynesville drilling program generates economic returns even at today’s low natural gas prices. We have cut back the number of wells we’re drilling and adjusted our completion schedule intentionally in order to generate free cash flow the way we used to pay down our debt and strengthen our balance sheet. We still expect 3% to 5% pro forma production growth in 2020, even with the reduced activity and the third completion schedule. Importantly, the lower volumes due to the agility completion schedule are just being deferred until later in 2020 and into early 2021 as previously anticipated. We prioritize free cash flow goals for 2020 over production growth, but have maintained adequate investment to grow our production on a longer-term basis. We’ve hedged almost half of our production over the remainder of 2020 and 64% of our production in 2021 and have strong financial liquidity of $612 million following our recent bond offering. So now, I’m going to turn it over to Ron to provide some specific guidance for the rest of the year. Ron?

Thanks, Jay. On slide 19, we provide financial guidance for the rest of this year for our analysts. This updated guidance reflects the impact of the deferred completion schedule, which we’ve mentioned on the call and which is shifting the turned to sales schedule on a number of wells to the later this year and into 2021. As a result, the production impact associated with those deferred completions will show up later this year and in the early part of 2021. We anticipate spending $400 million to $440 million on our drilling and completion activities and the associated impact on our 2020 production guidance as we now expect production to total 1.25 Bcfe to 1.3 Bcfe per day, of which 97% to 99% is expected to be natural gas. Our cost items are unchanged from prior guidance with LOE expected to average $0.23 to $0.27 per Mcfe, gathering and transportation cost expected to average $0.23 to $0.27 per Mcfe, production taxes at $0.06 to $0.08 per Mcfe, and DD&A at $0.85 to $0.95 per Mcfe. We continue to anticipate cash G&A will average $0.05 to $0.07 per Mcfe. For the rest of the call, we’ll take questions from the analysts who follow the company.

[Operator Instructions] Our first question is from Dun McIntosh with Johnson Rice. Please go ahead.

Good morning, Jay, Roland, Ron and Dan.

Good morning.

Just wanted to give a little more color on the back half of the year, you are pretty clear about looking to push completions out and try to capture a higher gas price but CapEx is fairly flat. So they can– on the lines of your spending this year to bring volumes on next year, just how are you all thinking about the trajectory for 2021 and balance in cash flow and CapEx?

So, you know what we do, we kind of mentioned this, we’re going to look at this free cash flow number of $150 million to $200 million plus. And then we want to assure that we can have that, and we back into what our CapEx budget should look like and also with that we want to have some growth. I mean we want have 2%, 3%, 4%, 5% growth and that just depends upon what our CapEx budget is and that depends upon prices and then we risk-adjust all that. I mean, we’re pretty comfortable with what the well results should look like. So we really risk-adjust the commodity price with the hedging, that’s where the 60% comes in, but you don’t get paid to grow. Now, you could go out of business if you don’t grow and you can impact your RBL if you don’t maintain it, which we would like to maintain that. We’d like to pay it down, we’d like to maintain where we are, if possible, and have a little growth and have a lot of profits. The key is, we said this two or three times, you really are [indiscernible] we are the low cost operator of the highest margins period and in the last two and a half years, we think a great strides to kind of take that pole position if we’re not in a pole or near it, with your oil or gas, so we want to stay there. I don’t think our leverage is too high but I think we do need to pay down our debt. I think we need to have lower cost of capital. And I think that’s one of our goals, because if you cure our cost of capital, that we’re really all in an unenviable position. Does that answer your question?

And then maybe just to add to that, if you would. I think as you look today at all those factors that Jay went over, I mean, we’re looking toward– we think a 6-operated rig program fits all those parameters right now. Now, things could be different three months from now and so we might have a different answer. And that’s one reason the operations group is planned to, by the end of the year, be at that level and so that would be a little bit higher activity level supported by the stronger natural gas prices that are out there, that we’ve already locked in with our hedging program. And so, we really see a very attractive year next year, that’s a great balance of a little bit higher activity, some growth in production at the same time, very substantial free cash flow generation, and we think all everything seems to be aligning up to that, to that type of year next year.

You know, there’s a lot of the noise in the numbers. I mean, you’ve got the Denham Series A preferred, we needed to get that noise out of the numbers as four shares, we said that we did stretched on the use of the RBL, we did that intentionally with the Covey Park because we knew what we should look like post-COVID and we do look like that. So when we issued the bonds, we did take the attention of liquidity and then, you can see even in the first quarter and we might almost $10 million and it’s a pretty hard quarter to have free cash flow wanted to have any profits too. As you can see, we are committed to hedging. Because we need to bring hedge whether were at the top, that we have or not, we should have a risk program for hedging, but now we’re going to start out with six rigs. We probably keep those six rigs for 2022 right now, that’s our goal, we can change it. We can change that, on the fourth quarter of 2019 we had nine rigs. Of course, in January of 2020, we had six, we’ll drop down to five, four, and end up at four. So we have definitely been toggling it, most of these rig contracts were well to well to well, and again, as you see, the service call is collapsing because the service companies are really in a fatigue position with these low prices. We should get these cost per foot down, like Dan had said. We’re probably at $1,400, $1,500 in 2018-2019, we’re lower a thousand now, hopefully we can get those down, so costs are coming our way, commodity prices are coming our way and we do control the rig count and we’ve shown you that, we’re not telling you things that we haven’t already done before. So I think that’s why in May and June the market trust us for the bond offering and the equity offering.

And Dan, I think that this quarter, like Jay phrased it at the very beginning, you’re really stress-tested the whole company with these very low gas prices, very low oil prices, we had no impairments. I don’t know how many companies can say that this quarter. And that just shows you that our cost is fundamentally low. We still achieved EBITDAX margin of 73%, probably the highest– the highest of any companies we tracked in the entire industry, and even if you strip the hedges away, we still had a 60% margin, even if it is that you don’t use your hedges. So I think that what you did see is that the company can withstand these low prices because of the really strong cost structure.

I mean, you know, a certain analogy, everybody went behind the card [indiscernible] see what you are made of. And we look pretty good.

Yes, absolutely. Thanks for the color. And it’s clear that you are executing at a high level despite a challenging take, but hopefully that gets better here in the back half of the year and into next year like you’re currently thinking about. Just for a quick follow-up, you have made a lot of progress on the balance sheet and congrats on getting off two deals. And as I said, was a really challenging environment for Q2. Ultimately, you talk about a long-term leverage target of under two times, what are some of the other levers you could pull over to potentially expedite that deleveraging, and I mean like I said, what you got done is remarkable in the second quarter. But is there anything else you could look to do in the capital markets or maybe M&A is still an option for deleveraging? What are you seeing on that front?

You know, on the M&A front, we are trying to position ourselves to be the funnel for companies that we’d like to be, to have a transaction in the Haynesville-Bossier area. Now, the markers that we’ve said are the low cost and half margins and the quality of inventory we have. So anything that we would do, we would have to de-lever the company. I mean, we don’t have to do anything right now, we’re in really good shape. We would like to continue to grow, get that opportunities there, but you know, we are not out aggressively seeking to get bigger for the sake of getting bigger. We’re not going to do that. I think we will have some opportunities. I think there’ll be some decisions that we’ll make, and the Board and the Jones will make about whether we want to grow or not. In fact, we’re always in discussions with the opportunities that are out there. And I’ll tell you, as you know, we’re very transparent company, we’ve got a respected management, because we’ve been through really, really hard times and we’ve not misbehaved. So I think most of the other companies, they would like to do something, they’d like to deal with a Comstock top culture and I think that’s a big plus we have, that they know us.

I think, Dun, if we just stick to our stake, there are basic plans here and stick to our knitting, we look ahead and just based on today’s commodity prices that are out there for the future, with about 2022, we’re under 2.5 times levered. So stick to our game plan and be very disciplined and achieve it through organic growth. It doesn’t happen overnight, but I think that’s an option too. So I think that’s really how we’re looking at it and think that we’ve taken the moves in the capital markets, we think to derisk the company, to make sure you can withstand the volatility in the markets. And if we will just stick to our plan, we will achieve our leverage goal.

And that is our plan and if something else comes as – that makes us a better company, then you know, we would probably act on it.

All right, great, thanks. Thank you for the call – sorry, thank you for the color. Looking forward to following along.

Thank you.

Thank you. Our next question comes from Phillips Johnston with Capital One. Please go ahead.

Hey, guys, thank you. Jay, now that the company’s scaled up in terms of size and now that your trading liquidity has increased with the larger float, I’m sure you’ve been talking to potential investors there, kicking the tires now that Comstock’s back on many focus-radar screens. Based on those conversations, what would you think is the most under-appreciated aspect to the Comstock story today?

Yes, it’s a great question. I think the Haynesville itself is kind of undiscovered, everybody has had their 2020 vision on the Appalachian and nobody has been asked to be educated on the Haynesville-Bossier. I think there is a select group of analysts, and you’re one of them, that take your binoculars closer to the Gulf of Mexico, close to Mexico, close to the LNG, close to industrial corridor, closer to where the midstream pipeline are, because that’s where Jerry’s vision was. And you said, well, okay, but I don’t have any opportunities there. And what we did is we created the opportunity where you could come look at the Haynesville. So one, I think is education. I don’t think that we’ve exposed the Haynesville properly because it’s in its infancy. I think two, Appalachian, you’ve got down six, seven, eight, ten companies there that are public, you don’t have that top of the landscape in the Haynesville. I mean, we sell more Haynesville-Bossier gas than antibody, we’re public. The others are mainly private or they’re really small, or they’re not a big player in the Haynesville. So I think education, one. I think execution, we’ve financed some calls from some big fund managers when we did the roadshows, telephonic roadshows for both the equity and bond, and they said, wow, your cost structure is like that. Wow, you do have those margins which Roland alluded to, wow, you do compare that favorable to the Appalachian. We didn’t know that. So yes, I think over– kind of like we had to do with you, you got to say prove it, and a lot of these companies have revenue, they’re going to dig all the way, we actually have proven it particularly in the second quarter when at the end wells fell off lot of these companies. A lot of Chapter 11, a lot of measures, a lot of paying, a lot of impairments. I think that tells you our top current is really, really well set, but we just need to get it out and broadcast it. And again, we did need more float, but we– I think the Jones said okay, I’ll issue shares at $5 as a company and the reason is they were diluted down some, if you just look at share percentages, but if you look through the percentages, you say now we’re going to have a float out there, because you can have the big institutional buyers without the float. I think that’s the same thing with the Denham shares, when Denham initially got there 26 million, 27 million, 28 million shares, I mean it’s private equity, they didn’t plan on holding those until they died and went to the grave. I mean, they plan on monetizing those. So I think at some point in time, you’re going to see that as they float and I think that’s going to help. So we’ve got to have more float. I think we’ve built it in. We got to continue to give results. We did amazing during the last quarter, the number of new research analysts that came out and, you know, it’s kind of hard to come out when things are pretty scary, but they did come out and we did get some really good ratings. I look at our bonds if you all bought bonds and you bought them at $0.90, whatever, I mean they were trading at $101 or $102 yesterday, you made money. If you bought equity at $5 at $6 and change, you made money. We’re making money for all these people and then we’re protecting those that are our base. You know, our base people. So I think that story is going to sell real well, period. Is going to sell well, we’ve got to deliver– Dan Harrison got to deliver on the call, he’s got to be real efficient on operations. We brought Ron Mills over here, we didn’t have really someone that was that connected with the analyst world out there, I think he’s super respected. Roland has done a great job for 30 years. We just have to tell the story, period. We got to get our debt down a little bit, but it’s mainly our cost of capital. We need to work in a year or two out that we get lower cost of funds. So, hope that answers your question.

Yes, absolutely does. You mentioned the Haynesville landscape, I asked you last quarter about big-picture thoughts on industry consolidation in the Haynesville. Maybe I’ll ask it again, especially now that just fixing the process of the pre-packaged Chapter 11.

Well, number one, let me tell how we look at PAT acquisitions. First of all, we look at rock quality, and I do think we understand rock quality and roads in Harrison County to DeSoto Parish, Caddo Parish, Sabine, we do rock quality. So, when we look at that, and I think that’s where our M&A group and David said and he’s fabulous when he was a leader at the Covey, I think that where David comes in as our head geologist. Again, we’ve got really good groups out here to understand the rock. We know most of the product rebacks companies. We know the management, we know the bankers and a lot of it is midstream cost, have you over drilled, what kind of the firm transportation commitments do you have. So we’ve looked at all of those and most of those companies growth is big. And you know, we want to grow. We want to have more acreage, but as Roland said, we’re not coveting to do something that doesn’t make us a much, much, much better company. Now, I think that some of those transactions are out there and we’re always willing to look at them and we look at them open eyes and if we can become better, they could become better. We delivered, and everybody is happy. Then, hopefully we’re smart enough to figure out how to do them. And then, at the same time, we’re smart enough to figure not to do deal, period. And I’d tell you, we always have a really good backstop. You asked a great question. If you pulled out a $1 billion from your pocket, not somebody else’s pocket or fund, you’re going to protect your investment, period. So we might have management, we might have a board, we may have all those things, but the thing that we have that most don’t, that none of them have, we’ve got a man who wrote a check from his pocket, period. And I’m telling you, that’s the phone call that we got two and a half years ago, that’s the difference in the trustworthiness of where you can go versus some others. That’s the big game-changer, and I think that’s the attractive part, so these opportunities that may come our way, I think they want to deal with Comstock.

That’s it from me, Jay. Thank you very much. Appreciate it.

Thank you. And our next question comes from Kashy Harrison with Simmons Energy. Please go ahead.

Good morning everyone and thank you for taking my questions. So in the prior presentation, there is some commentary on how a portion of the improvement in D&C costs was driven by reductions in completion intensity. We can clearly see the benefit of that as costs are at $1,000 and it seems like you’re going to be below $1,000 as you look to the second half of the year. I was just wondering if you could help us from a modeling standpoint, think through based on the early data that you guys are looking at, how to think about the impact to near-term productivity from the lower completion intensity designs?

This is Dan, so we are continuing to monitor the performance on those wells. It’s pretty hard to extrapolate out really good ore without getting probably six months of production on these wells. Everything that we’re looking at so far right now looks good. We’re just comparing what we’re recovering on these relatively downsized jobs and what we were getting on the larger jobs. Where we have the infield locations in the co-developed locations where we complete three or four wells side-by-side at the same time. So far on the data, we really haven’t seen that big of a difference to justify going back and continuing to pump the larger jobs. So that’s where we’re at, that’s still where we’re headed. We’ll continue to monitor the production and if we need to make some tweaks we will. We’ve also made some – our drilling costs were relatively flat, really last year and into the first quarter. I think we’re starting to see some benefit of a few things we’re doing there. We only turned seven wells to sales in the second quarter but we drilled – we had the 20 DUC at the end of Q2. If you just look at our drill cost, we are down 10% to 15% there since Q1. So I think that along with just holding the completion call is flat, we’re going to get to that $1,000 or probably below per foot. That’s our service goal stay in the same. I thought we’ve reached the bottom of the barrel in Q1. Who saw this whole COVID pandemic coming? That’s obviously put more stress on the pressure pumpers, and so we’ve seen another step down in service calls frac costs, basically from Q1 and to the end of Q2 and going into Q3. So that was a little bit unexpected. We had these targets in place really before that hit so that will help us maintain $1,000 a foot.

That’s helpful and good to know that it’s still in NPV positive decision. Then this is a good segue into my next question. At the 6-rig program that you all are thinking about for next year and the $1,000 per foot, I was wondering if you could just help us think through what that would imply from a CapEx standpoint based on what you know today.

Yes, I think if you’re looking at that program and just timing of when those wells gets completed etcetera, I think we’re targeting CapEx for next year, probably in the similar levels to this year, maybe slightly higher. Probably the $450 million to $475 million area. I think that’s going to be the overall cost of that program.

You can use that $450 million number and go a little north or south. That’s going to be a good kind of middle of the road number. Ron, is that good?

That’s good and that incorporates based on average and at least one incremental rig – plus or minus one incremental rig versus what we’re going to average this year.

Remember, we will have two frac crews and will toggle a third frac crew so we don’t have probably more than 15 DUCs at any given time.

That will be bringing more wells to sales. We have kind of a carryover effect from 2020, but that’s probably bringing 55 net wells to sales for that program. So it lines up pretty well especially with the current drill and complete cost that we can achieve, the expected commodity prices. It really sets up for a really good 2021 combination of all those factors.

When you look at those collars too, if you look at the Comstock inventory, Covey inventory when you blend them all in our drilling program has been a 50-50 Comstock-Covey. Might be a little more toward Comstock locations and Covey. We drilled in all south-east wells of our 305,000-acre footprint. So both of those assets in those locations have complemented each other. So when you look at these costs, they’re not skewed toward one little focused area. It’s why we drilled everywhere. That’s important.

You’re not going to drill all your wells in the – and maybe Elm Grove and the very top of our inventory, but it doesn’t make sense. You’d be shut in the entire year trying to complete them. So having a large footprint and having a lot of different areas, a lot of the program planning is around how do you efficiently bring the wells on, minimize downtime, create an overall best result and we use the entire field to achieve that. We don’t overly focus on one part of the acreage. Keeping it all spread out also gives you the lowest possible gathering cost because you don’t push any area too hard at one time.

I think when you look at those numbers again there hadn’t been a management group which includes Covey and Comstock that’s drilled and completed more of these extended lateral hence completed wells that we have. That’s a 237. We’ve got a lot of experience here.

That’s a lot of great detail. Thank you.

Great question.

Thank you. Our next question comes from Welles Fitzpatrick with SunTrust. Please go ahead.

Hey, good morning.

Good morning.

Can you guys have any early indications as to the second half non-op spend and 2021 non-op spend? It seems like the PE guys are slowing down a little bit, but maybe not quite at the pace that some folks would initially thought.

I’m sorry we missed the very first part of the question.

Just non-ups spend for the back half and then also any thoughts on non-ops spend?

Non-op for Comstock. We think that that’s a pretty light amount of activity for the rest of the year for our non-op activity because most of that they will be circulating AFEs out. So there was a lot of stuff that carried over from last year, especially in that first quarter. But for the last year, we do have a few projects that are going to be completed, but I think the overall budget for non-op is for the remainder of the year is in the $15 million area $15 million to $18 million of total spend for the next six months.

Okay. Perfect.

The acreage trades that’s part of that. Those actually help. I think some of the stuff we actually spent money for in the first quarter we either do exchange with and so I think that’s always the goal of the operators to the extent that we can figure out how to swap acreage back and forth, just so we can have a bigger interest in our own wells. Everybody is motivated to do that. They just take a long time to complete, but we did complete some significant ones in the second quarter, just kind of help the overall location count get a lot longer. I think we increased our percentage of long laterals. It also helps eliminate. What we like too is eliminating some of that non-outspend.

The beauty of the story in U.S. and non-outside but the beauty is 92% of our production we operate and we’ve got 95% HBP. So it’s a non-op. We do some of that but we’re not seeing any radical non-op operator out there drilling wells that are [indiscernible]. We don’t see any of that happen right now.

Good to hear. You had to jump back to the operator side. Maybe I’m a little bit late to this party but it recently crossover six months at least on the state data. Can you talk to the George mills? It looks like it’s drilled on some of your more Eastern acreage. That’ll be a month for five or six months. Was there anything different in the completion of the flow back on the well?

So now the George mills is definitely in a Tier 1 area over growth. We put that well along of labels in November of last year. We do have some limitations on the infrastructure over in that area. We have one primary gatherer that gathers all the gas in that area being the Tier 1 area that system stays relatively full. So here and there in some wells, we’re a bit limited as far as it might be getting them absolute max auto, but this will, in particular the George mills. We IP that will add about 35 million or 36 million a day and so essentially that rig we stayed in net 30 million to 35 million range for several months and I need to look at it in detail to give you the exact but that’s Bcf a month is right for several months after we put it online.

Okay, perfect. Great to see you. Thank you.

Thank you.

Thank you. And our next question is from Noel Parks with Coker & Palmer. Your line is open.

Good morning.

Good morning.

I hopped on a little late. I’m going to say, we talk about your improvement in the well cost per foot bringing it from $1,400, $1,500 down to $1,000, could you give some perspective on what you already accomplished in lowering it to that degree and what are the challenges still remaining to drive it down further as you seem to have pretty good confidence that you can go lower still?

We basically have been on a downward trend for several quarters now. That’s pretty much been driven by our drilling costs has been relatively – fairly unchanged during that trend. So really that was pretty much almost entirely driven by the completion side, mainly the frac costs. Just the frac health we’ve seen for several quarters. Just to provide our costs. Is really plummeted since back in probably mid-2018 timeframe. I think we’ve probably reached the bottom of the barrel here. I kind of felt we were there in the first quarter like I said earlier, but I think we’re probably there now. I just don’t see the frac costs probably going much lower than where they’re at today. Obviously we’ve done a pretty good job. I think today, we’re very efficient really from this point forward as far as getting that cost down a little bit further, it’s just really inefficiencies. We have gone to the downsides frac job that’s obviously part of the answer. We’ll continue to monitor performance on those, make sure we’re just getting the maximum NPV that we can. So it’s all about the efficiencies. It’s just getting a little bit better from here forward to get to that $1,000 a foot. So a little piece of that will be the frac costs because like I said, it did step down again from Q1 with the entire COVID-19 pandemic just kind of basically destroying the demand activities. The rig count drop activities drop but aside from that is just getting better at what we do. It’s saving a couple of those drilling the wells, it’s a couple of these lift frac in the wells. Hitting on the well sooner, minimizing any kind of problems, that’s kind of just really where the extra cost is, the extra efficiencies are.

Great, thanks. And just one other question, just thinking of the different regions the companies operate in over the years. We did actually have a transaction earlier in the week in North Louisiana and it got me wondering is there anything out there, any asset that could lure you back into conventional play at this point just given your inventory or any have in the Haynesville?

We’re not focused on the conventional so we probably would be the company to ask about that. We’re just going to stick with what got us here, and so we commented on that, we’re probably out of our court. The other color I’d like to add with, Dan, on your first question. Remember, he has been here since 2008. So every single well that we’ve ever touched in the Haynesville from 2008 all the way through today. He is forth tier and he has probably been involved in all that. So I think that’s really important when you ask the question, somebody he needs to be given the authority to hedge rate, and I don’t know if anybody who would have learned more authority than Dan would give you those answers. So I think that’s important. So a little detail there.

I’ll just add to that. We’ve got a pretty good staff here, and obviously we’ve got, got a lot of experienced people on our staff in Haynesville. That’s what creates the numbers that you see.

In fact, if we were to open a lot of make and I’ll give you all the answer but it would typically take too long.

Okay, I look forward to it some other time. Thanks so much.

Thanks for your time.

You bet.

Thank you. And this concludes our Q&A session for today. I would like to turn the call back to Jay Allison for his final remarks.

All right. Time I think is the most valuable thing we all have and so we are very thankful that you spent the last hour with us and we’re also very thankful to be positioned where we are and I’m telling you we’re very excited about the next 18 months to bring to the company. So thanks for your time. That’s it.

With that ladies and gentlemen, we thank you for participating in today’s program. You may now disconnect. Have a great day.