Earnings Call: Q2 2020

Aug 6, 2020

Ladies and gentlemen, thank you for standing by, and welcome to the Second Quarter 2020 Comstock Resources Incorporated Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. And please be advised that today's conference is being recorded. Now it's my pleasure to turn the call to Jay Allison, Chairman and Chief Executive Officer. Please go ahead. Thank you and everyone that's on the call. Welcome to the Comstock Resources Q2 2020 financial and Operating Results Conference Call. You can view a slide presentation during or after this call by going to our website atwww.comstockresources.com and downloading the quarterly result presentation. There you will find a presentation titled 2nd Quarter 2020 Results. I have 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'd 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 hit Slide 3, I want to 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 you from someone that has proven that they can create great wealth, you take that call and listen if you're wise. 2.5 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 HaynesvilleBossier shale in the United States was a Tier 1 natural gas play. And he put his $1,000,000,000 in the Comstock because the Haynesville Bossier has close proximity to the Gulf of Mexico, geological predictability, availability of midstream pipelines and proven historic well results. The Q2 2020 was the stressed test quarter for the energy sector and rebuild weaknesses that all of us don't ever look forward to seeing, but the vision set for 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 high margins in a 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 on during the valley 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 Q2 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 $210,000,000 Series A convertible preferred stock issued that we entered into as a part of the Covey Park acquisition. Then in June, we issued $500,000,000 in a senior notes offering that we used to repay borrowings under our revolving credit facility that greatly improved our financial liquidity as Roland will report on. We as a company and it's all 207 of 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 to well economics. Your support during trying times commit to you, our financial backers and equity stakeholders, that we will continue to focus on free cash flow generation overgrowth, focus on paying down our debt and strengthening our balance sheet and managing comp stock through the current low oil and natural gas price environment with our best in class cost structure, leading margins and depth of drilling inventory, we're very well positioned for the future. And in fact, we're eager to see what unfolds in the next 18 months because we see natural gas fundamentals strengthening during that window of time. Now if you go to Slide 3. Operationally, the Q2 was a fairly quiet quarter for us as we released our completion crews in April and we reduced our operated drilling rigs down to 4. 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 2nd quarter working to enhance our financial strength. In the current volatile and uncertain environment we are in with this COVID-nineteen pandemic, we were able to complete the 1st upstream common equity offering since 2018 larger than $50,000,000 The offering was also the 1st natural gas common equity offering since 2016. The offering allowed us to redeem our Series A convertible preferred stock at its face value of $210,000,000 and avoid the potential dilution associated with this conversion, We followed that offering up with a $500,000,000 senior notes offering to pay down borrowings on our bank credit facility. We reduced our outstanding bank borrowings from 89% of availability to 57%. While freeing up the bank credit facility, we increased our financial liquidity from $116,000,000 at the end of the first quarter to $612,000,000 currently. We further derisk our business plan by increasing our 2021 hedge position by 182% during the Q2, taking advantage of the improvements to natural gas futures in 2021. On the operations front, we are capturing reduced drilling and completion costs, which Dan Harris will talk about momentarily. Our 2nd quarter drilling and completion costs for lateral foot are down 26% from Q2 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 2021. Despite the very low oil and natural gas prices we had in the 2nd quarter, we still generated $36,000,000 in free cash flow, bringing our total free cash flow in 2020 to date to $51,000,000 The low oil and gas prices did limit the profits we generated in the quarter. Our oil and gas lease sales, including hedges, were $233,000,000 that's 79% higher than sales in the Q2 of 2019. Our adjusted EBITDAX came in at $162,000,000 which was 74% higher than 2019. Operating cash flow was $117,000,000 or $0.53 per share and was 77% higher than 2019. We did manage to have adjusted net income of $1,700,000 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 offerings we completed in the 2nd quarter. In May, we issued 41,325,000 shares in an underwritten equity offering, which was priced at $5 per share. We used the proceeds from the offering along with $13,000,000 of cash from the balance sheet to redeem the $210,000,000 Series A convertible preferred stock at its face value. The Series A convertible preferred stock was convertible into 52,500,000 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 at the preferred stock converted. The redemption saved us $21,000,000 per year by eliminating the 10% dividend we were paying. In April May, we exchanged $5,600,000,000 of our 7.5 percent senior notes through 2025 with certain holders for 767.96 newly issued shares of common stock. The exchange was done at market values above securities. Effectively, we issued the shares in the exchange at $7.30 per share. In June, we used proceeds from a $500,000,000 senior notes offering to repay $441,000,000 in borrowings under our revolving credit facility. The offering addressed our need to improve our financial liquidity. We used 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 tight financial liquidity was a primary reason for our credit rating that was downgraded in March by 2 of the agencies. The completion of the successful notes offering led to an upgrade to our rating by both Moody's and S and P. I will now have Roland Barnes 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 HaynesvilleBossier since 2016. And in the Q2 of 2020, production from our HaynesvilleBossier wells was 1,200,000,000 cubic feet per day and was 9% higher than the 1,100,000,000 cubic feet per day that Comstock and Covey Park produced in the Q2 of 2019. Low completion activity in the quarter caused production to decline slightly from the Q1. We only had 5.7 net wells turned to sales during the Q2. Given the continued weakness in gas prices since our last conference call, we've adjusted our completion schedule 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 Q3 production to decline a little further. We did add back 2 frac crews at the beginning of Q3 and we plan to add a 3rd frac crew later this year. We plan to turn 25 net wells to sales in the last 6 months of this year. Much of the new production from these wells will be on late this year, setting us up for a strong exit rate and for some growth in 2021, but not in time to show growth in the Q3. 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 Q2. We had 23% of our oil production curtailed or shut in in the Q2 due to the very low oil prices. 4% of our natural gas production was also shut in in the 2nd quarter as compared to 5% in the Q1 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 this 4%. On Slide 7, we cover our hedging program. During the first 6 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 $98,700,000 in the 1st 6 months this year. With improvement in futures natural gas prices that we saw in the Q2, we have added substantially to our hedge book. Since we last reported earnings, we've added 10,000,000 cubic feet a day of natural gas swaps for the Q3 of this year and another $20,000,000 of additional swaps for the Q4. And then we've also added 25,000,000 25,000,000 cubic feet of natural gas collars in the Q4 of this year. But most substantially, we added up 128,000,000 cubic feet of natural gas collars in 2021, which protect us at an average floor price of $2.47 but give us exposure to the higher prices that we are expecting for next year. For the rest of 2020, we have 608,000,000 cubic feet of our gas hedged and 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 668,000,000 cubic feet of our expected 2021 gas production and the weighted average floor protection price for those hedges is $2.51 Our 2021 gas hedge increases to 864,000,000 cubic feet per day at an average floor price of $2.51 if certain swaptions are exercised in the Q4 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 Q2 of this year. Our production for the Q2 totaled 119 Bcfe, including 360,000 barrels of oil. This is 163 percent higher than our production in the Q2 of last year. Our oil and gas sales, including realized hedging gains, were $232,000,000 or $233,000,000 which was 79% higher than 2019. Oil prices in the quarter averaged $37.89 per barrel and our gas prices averaged $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 $162,100,000 which was 74% higher than the Q2 of 2019. Operating cash flow was $117,500,000 which was 77% higher. We did report a net loss of $60,000,000 for the quarter or $0.29 per share, but that loss was mainly attributable to $65,600,000 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 then certain other unusual items was $1,700,000,000 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 1st 6 months was 244 Bcfe, including 814,000 barrels of oil. That is 194% higher $1,000,000 or 92 percent 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 $364,000,000 or 91% higher than 2019 and operating cash flow was $273,000,000 which was 100 percent higher than 2019. We reported a net loss of $30,000,000 for the 1st 6 months of 2020 or $0.15 per share. But again, that was mainly due to the unrealized hedging loss from the Q2. So excluding that, the unrealized hedging loss from the mark to market and other unusual items, the net income for the first half of the year was $28,000,000 or $0.14 per share. On Slide 10, we detail our operating costs for Mcfe. Our operating costs averaged $0.54 in the 2nd quarter as compared to the Q1 rate of $0.50 Gathering costs were $0.22 per Mcfe, production taxes averaged 0 point $5 and field level costs were $0.27 The taxes and the field level cost in the Q2 did include some prior period ad valorem and franchise tax adjustments that we recorded in the Q2. On Slide 11, we detail our corporate overhead cost per Mcfe and our cash G and A cost per Mcfe averaged $0.06 in the second quarter, which is exactly unchanged from what we had in the Q1. On Slide 12, we show that our depreciation, depletion and amortization per Mcfe produced, that averaged $0.87 in the 2nd quarter, which was 1% lower than the $0.88 that we had in the 1st quarter. On Slide 13, we recap our 2nd quarter and then 1st 6 months of 2020 capital expenditures. We spent $75,000,000 on development activities in the Q2, of which $61,000,000 was related to our operated Haynesville Shale properties. For the 1st 6 months of this year, we spent $205,000,000 including the $165,000,000 spent on our operated Haynesville Shale program. We drilled 26 or 20.1 net operated horizontal Haynesville well so far this year. We also completed 15 or 9.6 net wells that we drilled in 2019. We spent about $40,000,000 on non operated or other activities so far this year. We generated operating cash flow of $273,000,000 in the 1st 6 months of this year, resulting in free cash flow of $51,000,000 after we paid 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 4 rigs in April, which was down from 6 in January, we've added back a 5th operated rig this week and we plan to add a 6th rig by the end of the year. We expect to spend approximately $400,000,000 to $440,000,000 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 and planning our capital expenditure activity and we're targeting to have $150,000,000 to $200,000,000 of annual free cash flow as we set our spending 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 Q2, as Jay said, we were very active in the capital markets issuing 41,300,000 shares of common stock to redeem the Series A preferred stock and issuing $500,000,000 of new unsecured notes to termite a portion of the borrowings outstanding under our credit facility. We also completed some debt for equity exchanges totaling $5,600,000 in exchange for 767 96 newly issued common shares. We currently have $800,000,000 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 I mean what will free cash flow we'll have for the rest of this year and then what we will generate in 2021. With the quarter ending cash position of $12,000,000 our current liquidity now stands at $612,000,000 We have just under $2,000,000,000 of senior notes outstanding comprised of $619,000,000 of the 7.5 percent senior notes due in 2025 and then 1,350,000,000 dollars of our 9.75 percent 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 4 times. So we are 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 2nd 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% operated 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 release in our frac crews in early April, we've not turned any additional wells to sales since the time of our last call. So our D and C well count still stands at 237 gross wells per day sales since we reentered the play in 2015. We're currently running 4 rigs and we're in the process of moving in a 5th rig this week. We also plan to add a 6th rig sometime before year end. Due to the frac holiday that did start 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 2 fry crews back to work at the end of June and we plan to add a 3rd crew within the next couple of months as we prepare to draw down our number of docks and take advantage of the anticipated higher gas prices heading into the fall. Over on slide 16, this is an updated breakdown of our HaynesvilleBossier 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 18 49 locations. This represents an average of 73% working interest on the remaining operated inventory. In addition to the operated inventory, we also have 13 10 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 5 38 short laterals, 1,005 medium laterals and 977 long laterals. Our gross operated inventory actually increased by approximately 6% in the 2nd 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 benches, 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 DMC cost. These results track only our medium to long laterals which have lateral lengths of greater than 6,000 feet. Our D and C costs continue to trend down. In the Q2, we achieved our lowest all in D and C costs, 2 to 8 at $10.28 per foot. This reflects the D and C cost on the 7 long lateral wells that returned to sales in the Q2 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 costs associated with the historically low industry activity levels. We are continuing to pump the smaller modified frac design that we started pumping early in the year. This is primarily on our infill and co developed locations and this has also been a factor in our oil well cost. As stated on our last call, we're maintaining a near term goal of reducing our D and C cost 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. This summarizes the operations. I'm going to turn it back over to Jay for some final comments. Okay. 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 for questions. So if you'll 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 through the current low oil and natural gas price environment. In a while current, natural gas prices remain relatively low. The outlook for natural gas has improved substantially for late 2020 2021, driven by our expectations for significant declines in natural gas supply in 2020 2021 due to a continued reduction in natural gas directed drilling and completion activities and less associated gas production from 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 are drilling and adjusted our completion schedule intentionally in order to generate free cash flow that we will use to pay down our debt and strengthen our balance sheet. We still expect a 3% to 5% pro form a production growth in 2020 even with the reduced activity and deferred completion schedule. Importantly, the lower volumes due to the adjusted completion schedule are just being deferred until later in 2020 and into early 2021 and previously anticipated. We have prioritized free cash flow goals to 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 64% of our production in 2021 and have strong financial liquidity of $612,000,000 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, it's yours. 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 turn to sales schedule on a number of wells to 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 2020 one. We anticipate spending $400,000,000 to $440,000,000 on our drilling and completion activities, And the associated impact on our 2020 production guidance is we now expect production to total 1.25 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 point $7 per Mcfe gathering and transportation costs expected to average $0.23 to $0.27 per Mcfe production taxes at $0.06 to $0.08 per Mcfe and DD and A at $0.85 to $0.95 per Mcfe. We continue to anticipate cash G and 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. Thank you. Our first question is from Don MacIntosh with Johnson Rice. Please go ahead. Good morning, Jay, Roland Ryan. Just wanted to get a little more color on the back half of the year. You all are pretty clear about looking to push completions out and try to capture a higher gas price, but CapEx is fairly flat. So thinking along the lines of your spending this year to bring volumes on next year, just kind of how are you all thinking about the trajectory for 2021 and balancing cash flow and CapEx and growth? Yes. What we do, we kind of mentioned this, we're going to look at this free cash flow number of $150,000,000 to $200,000,000 plus and then we want to assure that we can have that. And then we back into what our CapEx budget should look like. And also with that, we do want to we want to have some growth. I mean, we want to 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 for that 64% comes in. But we you don't get paid to grow. Now you could go out of business if you don't grow, then you can impact your RBL if you don't maintain it. We'd still like to maintain that. We'd like to pay it down, but we'd like to maintain where we are, if possible, and have a little growth and have a lot of profits. And the key is, we said this 2 or 3 times, you really are in the catbird seat if you're the low cost operator with the highest margins, period. And in the last two and a half years, we've taken great strides to kind of take that pole position. If we're not in the pole, we're near it, Whether you're oil or gas, 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, then we really, really are in an infillable position. Does that answer your question? Yes. And Don, maybe to add to that, you would I think as we just as you look today at all those factors that Jay went over, I mean, we kind of we're looking toward kind of a we think a 6 operated rig program fits all those parameters right now. Now things could be different 3 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 kind of be at that level. And so that would be a higher 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 the everything seems to be aligning up to that type of year next year. We get a lot of the noise in the numbers. I mean, you've got the denim Series A preferred. We needed to get that noise out of the numbers as for shares. We needed we said that we did stretch on the use of the RBL. We did that intentionally with the Covey purchase because we knew what we should look like post Covey, and we do look like that. So when we issued the bonds, we did take the tension off of liquidity. And then you can see even in a very stressed quarter, we've made almost $2,000,000 and it's a pretty hard quarter to have free cash flow, 1, and to have any profits, 2. And you can see we are committed to hedging because we need to be hedged. Whether we're at the top debt we have or not, we should have a we should have a risk program for hedging. But now we're going to we'll start out with 6 rigs. We'll probably keep those 6 rigs for 2022 right now. That's our goal. We can change it. We changed that. On the Q4 of 2019, we had 9 rigs. Of course, in January of 2020, we had 6. We dropped down to 5.4, we ended up to 4. So we definitely can toggle that. Most of these rig contracts are well to well to well. And again, as you see, the service costs collapsing because the service companies are really in a fatigue position with these low prices. We should get these costs per foot down like Dan had said. We're probably $14,000,000 $1500 in 20 19. We're a little over $1,000 now. Hopefully, we can get those down. So costs are coming our way. Commodity prices are coming our way if you're gas 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 June, the market trust us with the bond offering and the equity offering. And Don, I think that this quarter, like Jay phrased at the very beginning, you 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. That just shows you that the our cost is fundamentally low. We still achieved an EBITDAX margin of 73%, probably the highest, I mean the highest of any companies we track in the entire industry. And even if you'd strip the hedges away, we start a 60% margin, even if you do said, 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, a simple analogy, everybody went behind the carton on the Wizard of Bobs, see what you're made of. And we look pretty good. Yes, absolutely. Thanks for the color. And it's clear that you all 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 all are clearly thinking about. But just for a quick follow-up, you all have made a lot of progress on the balance sheet and congrats on getting off 2 deals. And as I said, well, it was a really challenging environment for 2Q. Ultimately, you talk about a long term leverage target of under 2 times. What are some of the other levers you all could pull over to potentially expedite that deleveraging? And I mean, do you 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 is M and A still an option for deleveraging? How are you what are you seeing on that front? Well, on the M and A front, we are trying to position ourselves to be the funnel for companies that would like to be to have a transaction in the HaynesvilleBossier area. Now the markers that we've said are the low cost and the high margins and the quality of inventory we have. So anything that we would do, we would have to delever the company, period. I mean, that's just we don't have to do anything right now. We're in really good shape. We would like to continue to grow if that opportunity is there. But we're not out aggressively seeking to get bigger for the sake of getting bigger. We're not going to do that, period. I think we will have some opportunities. I think there'll be some decisions that we'll make and the Board and the Joneses 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 a very transparent company. We've got respected management because we've been through some really, really hard times and we've not misbehaved. So I think most of the other companies that would like to do something, they'd like to deal with a Comstock type culture. And I think that's a big plus we have, but they know us. I think, Don, if we just stick to our basic plan here and stick to our knitting, we look ahead and just based on today's commodity prices that are out there for the future, By 2022, we're under 2.5 times lever. So we can 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 de risk the company to make sure you can withstand the volatility in the markets. And if we will just stick to our plan, we'll achieve our leverage goal. That is our plan. And if something else comes, as Sweden's at, that makes us a better company, then we would probably act on it. All right, great. Thanks, y'all. Thank you for the color. No, no, thank you. Looking forward to following along. Yes, sure. Thank you. Thank you. Our next question comes from Philip Johnston with Capital One. Please go ahead. Hey, guys. Thank you. Jay, now that the company has 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 that are kicking the tires now that Comstock's back on many folks' radar screens. Based on those conversations, what would you think is the most sort of underappreciated aspect of 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 HaynesvilleBossier. I think there's a select group of analysts and you're one of them that you took your binoculars close to the Gulf of Mexico, close to Mexico, close to LNG, close to industrial corridor, close to where the midstream pipelines are, and that's where Jerry's vision was. And you said, well, okay, but I don't have any opportunities here. So and what we did is we created the opportunity where you could come look at the Haynesville. So one, I think it's education. I don't think that we've exposed the Haynesville properly because it's in its infancy. So I think 2, the Appalachian, you've got 10,06, 7, 8, 10 companies there that are public. You don't have that type of a landscape in Haynesville. I mean, we sell more HaynesvilleBossier gas than anybody, we're public. The others are mainly private or they're really small or they're not a big player in the Haynesville. So think education, 1, I think execution. We've had some calls from some big fund managers when we did the road shows, telephonic road shows for both the equity and bonds. And they'd say, wow, so your cost structure is like that, while you do have those margins, which Roland alluded to, while you do compare that favorable to the Appalachian, we didn't know that. So, yes, I think over and over and over kind of like we had to do with you, you got to say, prove it. A lot of these companies have revenue going to go well, we actually have proven it and particularly in the Q2 when the envelope will fell off a lot of these companies, Lot of Chapter 11s, lot of misery, lot of pain, lot of impairments. I think that tells you our time curves are really, really well set. But we just need to get out and broadcast it. And again, we did need more float. So we I think the Joneses said, okay, I'll issue shares at $5 as a company. And the reason is and they were diluted down some, if you just look at share percentages. But if you look through the percentages, you say, no, we've got to have the float out there because you can't have the big institutional players without the float. I think that's the same thing with the denim shares. When denim initially got their $26,000,000,000 $27,000,000 $28,000,000,000 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 real float, and I think that's going to help us. So we've got to have more float. I think we've built it in. We've got to continue to give results. It's amazing during the last quarter, the number of new research analysts that came out. And 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're trading at $1.01 $1.02 yesterday, you've made money. If you bought equity at $5 it's $6 and change, you made money. We're making money for all these people, period. And then we're protecting those that are our base, our base rate people. So I think that story is going to sell real well, period. It's going to sell well. We've got to deliver. Dan Harrison has got to deliver on the cost. 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 handlers 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 2 after we get lower cost of funds. So I hope that answers your question. Yes, absolutely, it does. You mentioned the Haynesville landscape. I know I asked you last quarter about just big picture thoughts on industry consolidation in the Haynesville. Maybe I'll ask it again, especially now that Chesapeake is in the process of the prepackaged JETRA LUM. We number 1, let me tell you how we look at pad acquisitions. First of all, we look at rock quality. And I do think we understand rock quality, whether it's in Harrison County, DeSoto Parish, Caddo Parish, Sabine, we do know rock quality. So we look at that and I think that's where our M and A group and David Terry leads that and he's fabulous and he was a leader at Covey. I think that's where Nate Tedford comes in as our head geologist. Again, we've got really good groups out there to understand the rock. We know most of the private equity backed companies, we know the management, we know the backers. And a lot of it is what's your midstream cost, Have you over drilled? What kind of farm transportation commitments do you have? So we've looked at all of those and most of those companies, Cliff Chesapeake. And 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 were out there, and we're always willing to look at them. We look at them at open eyes. And if we can become better, they can become better and we delever and everybody is happy, then we will hopefully, we're smart enough to figure out how to do them. And then at the same time, we're smart enough to figure out not to do them, period. And I tell you, we always have a really good backstop. You asked a great question. If you pull out $1,000,000,000 from your pocket, not somebody else's pocket or a fund, you're going to protect your investment, period. So we may have management, we may have a Board, we may have all those things. But the thing that we have that most don't and 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 2.5 years ago. That's the difference in the trustworthiness of where we can go versus some others, that's the big game changer, period. And I think that's the attractive part of some of these opportunities that may come our way. I think they want to deal with a comp stock. So another question? No, that's it. That's it for me, Jay. Thank you very much. Appreciate it. Thank you. And our next question comes from Kashy Harrington with Simmons Energy. Please go ahead. Good morning, everyone, and thank you for taking my questions. So in the prior presentation, there was some commentary on how a portion of the improvement in D and C costs was driven by reductions in completion intensity. And we can clearly see the benefit of that as costs are at, call it, 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 you guys are looking at, how to think about the impact to near term productivity from the lower completion intensity designs? Hey, so this is Dan. So we are continuing to monitor the performance on those wells. It's hard to it's pretty hard to extrapolate out really good EOR without getting probably 6 months of production on these wells. Everything that we're looking at so far right now looks good. I mean, we're just comparing what we're recovering on these relatively downsized jobs to what we were getting on the larger jobs. And where we have the infill locations and the co developed locations where we complete 3 or 4 wells side by side at the same time. I mean 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 kind of where we're at. That's kind of 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 Q1. I think we're starting to see some benefits and a few things we're doing there. We only turned 7 wells to sales in the 2nd quarter, but we drilled we had the 20 DUC at the end of Q2. And if you just look at our drill cost, we're down 10% to 15% there since Q1. So I think that along with just holding the completion cost flat, we're going to get to that 1,000 books or probably below per foot. And that's what service cost staying the same. I thought we'd reach the bottom of the barrel in Q1. I mean, 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 cost, frac cost basically from Q1 and the end of Q2 and going into Q3. So that was a little bit unexpected. We kind of had these cost targets in place really before that hit. So that will help us maintain the $1,000 a foot. That's helpful and good to know that it's still an NPV positive decision. And then I guess this is a good segue into my next question. At the 6 rig program that you all are thinking about for next year and into 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 the just timing of when those wells get completed, etcetera. I think we're targeting CapEx for next year probably in the probably kind of similar levels to this year, maybe slightly higher, probably $450,000,000 to $475,000,000 area. I mean, I think that's going to be kind of the overall cost of that program. You can use that $450,000,000 number, go a little north or south, that's going to be a good kind of middle of the road number. Ron, is that good? Yes. That's good. That incorporates basically on average at least 1 incremental rig or plus or minus 1 incremental rig versus what we're going to average this year. Remember, we'll have 2 frac crews and we'll toggle a 3rd frac crew every now and then. So we don't have probably more than 15 DUCs at any given time. And that will be bringing more wells to sales. We'll have kind of that carryover effect from the 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 drilling complete costs that we can achieve, the expected commodity prices, it really sets up for a really good 2021, the combination of all those factors. When you look at those costs too, if you look at the Comstock inventory, Covey inventory, when you blend them all in, our drilling program has been fifty-fifty Comstock Covey, maybe a little more toward Comstock locations in Covey. And we drilled north, south, east and west of our 305 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. I mean, it's where we've drilled everywhere. That's important. Bobby, we'd like to throw all your wells in the and maybe Elm Grove and those at the very top of our inventory, but that doesn't make sense. You can't you'd have you'd be shut in the entire year trying to complete them. So having a large footprint and having a lot of different areas, I mean a lot of the program planning is around how do you efficiently bring the wells on, minimize downtime, create kind of an overall best kind of result. And we use the entire field to achieve that. So we don't overly focus on one part of the acreage. Keeping it all spread out also gives you the lowest possible gathering costs because you don't push any area too hard at one time. So think 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 and completed wells than we have, that's at 237. So we've got a lot of experience here. That's a lot of great detail. Thank you. Yes. Great question. Thank you. Our next question comes from Welles Fitzpatrick with Tuohyst. Please go ahead. Hey, good morning. Good morning. Can you guys have any early indications as to second half non op spend and 2021 spend? It seems like the PE guys are slowing down a little bit, but maybe at a maybe not quite at the pace that some folks had initially thought? I'm sorry, we missed the very first part of the question. You came on strong and we've muted you a little bit. Now we brought you back up. Fair enough. Fair enough. No, just non op spend for the back half and then also any thoughts on non op spend and Okay. Yes, non op for Comstock. Yes, we do 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 would be circulating the AFEs out. So there was a lot of stuff that carried over from last year, especially in that Q1 before 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, what, dollars 15,000,000 area, dollars 15,000,000 to $18,000,000 of total spend for the next 6 months. Okay, perfect. Yes, the acreage trade that's part of that. We those actually help. I think some of the stuff we actually spent money for in the Q1, we'd have to do an exchange with. And so I think that's always the goal of the operators. We 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's motivated to do that. They just take a long time to complete, but we did complete some significant ones really in the second quarter, just kind of help the overall location count get a little longer. I think we increased our percentage of long laterals. It also helps eliminate like what we like to is eliminating some of that non spend. The beauty of the story in U. S. To non op side, but the beauty is 92 percent of our production we operate and we've got what 95% HPP. So it's a non op. We do budget some of that, but we're not saying any radical non op operator out there drilling wells that are maybe iffy. We don't see any of that happening right now. Good to hear. And you had to jump back to the operated side. Maybe I'm a little bit late to this party, but it recently crossed over 6 months at least on state data. Can you talk to the George Mills? It looks like it's drilled on some of your more eastern acreage. I mean, did B a month for kind of 5 or 6 months? I mean, was there anything different in the completion or the flow back on that well? So, no, the George Mills is definitely in a Tier 1 area over in Elm Grove. We put that well on, I believe it was in November of last year. We held we do have some limitations on the infrastructure over in that area. We got one primary gatherer that gathers up all the gas in that area and being a Tier one area that that system has stayed relatively full. So here and there in some wells we're a little bit limited as far as maybe getting them absolute max out of them. But this well in particular the George Mills we IP that well at about $35,000,000 or $36,000,000 a day. And so essentially that rate we stayed in that $30,000,000 to $35,000,000 range for several months. 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. Thanks, guys. Thank you. Thank you. And our next question is from Noel Parks with Coker and Palmer. Your line is open. Good morning. Good morning. I hopped on a little late, so sorry if something you touched on. We're re penalizing you. Okay. I was going to say, can we talk about your improvement in the well cost per foot, you're bringing it from $14,000, dollars 1500 down to $1,000 Could you kind of give some perspective on sort of what you've already accomplished in lowering it to that degree? And sort of what are the challenges still remaining to drive it down further? You seem to have pretty good confidence that you can go lower still. Yes. So we've basically been on a downward trend for several quarters now. That's pretty much been driven by our drilling cost has been relatively fairly unchanged during that trend. So really that was pretty much almost entirely driven by the on the completion side, mainly the frac costs. I mean, just the frac costs we've seen for several quarters, just the provider cost, I mean, has really plummeted since back in probably mid-twenty 18 timeframe. We've I think we've probably reached the bottom of the barrel here. I mean, I kind of thought we were there in the Q1, like I said earlier, but I think we're probably there now. I just don't see the frac cost probably going much lower than where they're at today. I mean, 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. I mean, we have gone to the downsized 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. But 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 cost because like I said, it did step down again from Q1 just with the entire COVID-nineteen pandemic just kind of basically destroying the demand activities, the rig counts drop, activities drop. But aside from that, it's just getting better at what we do. It's saving a couple of days drilling the wells. It's a couple of days less fracing the wells, getting on and off the well sooner, minimizing any kind of problems. That's kind of just really where the extra cost is, the efficiencies are. Great. Thanks. And just one other question. Just thinking of the different regions the company has operated 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 you already have in the Haynesville? Yes, we're not focused on the conventional. So we probably wouldn't 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'd probably be out of our court. So the other color I'd like to add with Dan on your first question. Remember, he's been here since 2,008. So every single well that we've ever touched in the Haynesville from 2008 all the way through today, he's worked here and he's probably been involved in all that. So I think that's really important when you ask a question to somebody, he needs to be given the authority to answer it. And I don't know if anybody would have earned more authority than Dan would have given you those answers. I think that's important. So a little detail there. I'll just add to that. I mean, we've got pretty good staff here. And obviously, our we've got a lot of experienced people on our staff in Ninesville. I mean, that's what creates the numbers that you see. In fact, if we were to open a line up to them, they could all give you their own answer, but you could take too long. Okay. Well, I look forward to it some other time. Thanks a lot. Thanks for your time. You bet. Thank you, Noah. Thank you. And this concludes our Q and A session for today. I would like to turn the call back to Jay Allison for his final remarks. All right. Again, we are time, I think, is the most valuable thing we all have. And so we are very thankful that you spent last hour with us. And we're also very thankful to be positioned where we are. And I'm telling you, we are very excited about what the next 18 months could bring to the company. So I thank you for your time. That's it. And with that, ladies and gentlemen, we thank you for participating in today's program. You may now disconnect. Have a great day.