Comstock Resources, Inc.

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 now listening. After the speaker's presentation, there will be a question and answer session. To participate on that portion of the call, you will need to press star 1 on your telephone. And please be advised that today's conference is being recorded. If you require any further assistance, please press star and 0. 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 second quarter 2020 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly result presentation. There you'll find a presentation titled, Second Quarter 2020 Results. I have Jay Allison, Chief Executive Officer of Comstock, and 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 two, it's a disclaimer. Please refer to slide two in our presentations and note that our discussions today will include forward-looking statements, within a meeting 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 three, I want to make some comments. First of all, it's a privilege to be able to talk to everybody. You know, 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. Two and a half years ago, Comstock Resources received that 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. You know, every train has a conductor, and ours is Jerry Jones. He believed in natural gas in America. He believed that the Hainesville-Bossier Shale in the United States was a Tier 1 natural gas plate. and he put his billion dollars into Comstock because the Hainesville Boat Show has close proximity to the Gulf of Mexico, geological predictability, availability of midstream pipelines, and proven historic well results. The second quarter of 2020 was the stress test quarter for the energy sector and revealed weaknesses that all of us don't ever look forward to seeing again. But the vision set for two and a half 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 and a tier one area for natural gas in America. Without the Jones's 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 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 Comstock. 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 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 that'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 oil economics. Your support during trying times in the oil and gas industry is greatly appreciated. We commit to you, our financial backers and equity stakeholders, that we will continue to focus on free cash flow generation over growth, 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'll go to slide three. 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. In the current volatile and uncertain environment we're in 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 followed 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-risk our business plan by increasing our 2021 hedge position by 182% during the second quarter, 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 Harrison will talk about momentarily. Our second quarter drilling and completion costs for lateral foot are down 26% from second quarter 2019 costs. 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, including hedges, were $233 million. That's 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 53 cents per share, and was 77% higher than 2019. We did panic. to have adjusted that income of $1.7 million or one penny per share for the quarter. If you go over to slide four, on slide four, we recap the equity and senior notes offerings we completed in the second 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 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 16th of 2020. The offering was accretive to the company as we saved the company from 11,175,000 shares that would have been issued if 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 to 2025 with certain holders for 767 and 96 newly issued shares of common stock. The exchange was done at market values of both securities. Effectively, we issued the shares in 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 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 two of the agencies. The completion of the successful notes offering led to an upgrade to our rating by both Moody's and S&P. I will now have Roland Barnes summarize our financial results for the quarter. Thank you, Roland.

All right. Thanks, Jay. On slide five, we combined Comstock and Covey Parks production from the Hainesville-Bossier since 2016. And in the second quarter of 2020, production from our Hainesville-Bossier wells was 1.2 billion cubic feet per day and was 9% higher than the 1.1 billion cubic feet per day that's 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 in 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 frack crews at the beginning of the third quarter, and we plan to add a third frack 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 for 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 third quarter. Slide six 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 percent of our oil production curtailed or shut in in the second quarter, due to the very low oil prices. Four percent of our natural gas production was also shut in in the second quarter, as compared to five percent 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 two to three percent in the second quarter. But given the significant amount of offset operator completion activity, the shut-in activity, you know, came in at this four percent. On slide seven, 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 the 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. And then we've also added 25 million cubic feet of natural gas collars in the fourth quarter of this year. But most substantially, we added up 128 million 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 million cubic feet of our gas collars 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 million cubic feet of our expected 2021 gas production, and the weighted average floor protection price for those hedges is $2.51. Our 2021 gas hedged increases to $864 million cubic feet per day and 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 percent of our anticipated 2021 production hedged. On slide eight, 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 percent 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 79 percent 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 $162.1 million, which was 74% higher 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 dollars for the quarter or 29 cents per share but that loss was mainly attributable to 65.6 million dollar 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 31st ballot sheet. Adjusted net income, excluding that mark-to-mark hedging loss and then certain other unusual items, was $1.7 billion, or one cent, per diluted share for the quarter. On slide nine, 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 real house hedging gains, were $504 million, or 92% higher than the same period in 2019. Oil prices averaged $42.59 per per barrel, and gas prices averaged $1.96 per NCF, including hedging gains. Overall, our natural gas price realization was down 23 percent in 2020 versus 2019. Adjusted EBITDAX came in at $364 million, or 91 percent higher than 2019, and operating cash flow was $273 million, which was 100 percent higher than 2019. We reported a net loss of $30 million for the first six months of 2020, or 15 cents 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 and other unusual items, the net income for the first half of the year was $28 million, or 14 cents per share. On slide 10, we detail our operating costs for MCFE. Our operating costs averaged 54 cents in the second quarter as compared to the first quarter rate of 50 cents. Gathering costs were 22 cents for MCFE, production taxes averaged 5 cents, and field level costs were 27 cents. The taxes and the field level cost in the second quarter did include some prior period ad valorem and franchise tax adjustments that we recorded in the second quarter. On slide 11, we detail our corporate overhead costs for MCFE, and our cash G&A costs for MCFE averaged six cents in the second quarter, which is exactly unchanged from what we had in the first quarter. On slide 12, we show that our depreciation, depletion, and amortization per MCFE produced, that averaged 87 cents in the second quarter, which is 1 percent lower than the 88 cents that we had in the first quarter. On slide 13, we recap our second quarter and the 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 Hainesville Shale properties. For the first six months of this year, we spent $205 million, including the $165 million spent on our operated Hainesville Shale program. We drilled 26 or 20.1 net operated horizontal Hainesville 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 $273 million in the first six months of this year, resulting in free cash flow of $51 million after we paid the dividend on the preferred shares. We continue to maintain very responsive to the changing natural gas prices, and remain focused on generating significant free cash flow. After dropping our operating rig count to four rigs in April, which was down from six in January, we've added back a fifth operating rig this week, and we plan to add a sixth rig by the end of the year. We expect to spend approximately $400 to $440 million this year to drill 67 or 42.8 net Hainesville wells and to turn 79 or 42.3 net Hainesville 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 six 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 under 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 evolving 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 20 – I mean, what we'll – the 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 9.75% 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 four 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 second quarter drilling results and more details. 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 releasing our frack crews in early April, we've not turned any additional wells to sales since the time of our last call. So our DNC well count still stands at 237 gross wells turned to sales since we reentered 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 year-end. Due to the frack holiday that did start in early April, our operated duct well count increased to a maximum of 20 wells by the end of the second quarter. We currently have 16 operated ducts at this time. We put two fry 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 draw down our number of ducts and take advantage of the anticipated high gas prices heading into the fall. Over on slide 16, this is an updated breakdown of our Hainesville-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 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 a 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 DMC costs continue to trend down. In the second quarter, we achieved our lowest all-in DMC cost to date at $1,028 per foot. This reflects the DMC cost on the seven long lateral wells that returned to sales in the second quarter, all in the month of April, before we released our frack 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 oral well cost. As stated on our last call, we're maintaining a near-term goal, 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.

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 to 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. You know, this year we're primarily focused on pre-cash flow generation, as we stated over and over, and managing the company through the current low oil and natural gas price environment. You know, 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 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 Hainesville drilling program generates economic returns even at today's low natural gas prices. We've cut back the number of wells we're 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 forma 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 in early 2021 than previously anticipated. We have prioritized free cash flow goals in 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, cheers. 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 2021. We anticipate spending 400 to $440 million on our drilling and completion activities. And the associated impact on our 2020 production guidance is we now expect production to total 1.25 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 23 to 27 cents per MCFE. Gathering and transportation costs expected to average 23 to 27 cents 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.

Thank you. And as a reminder, ladies and gentlemen, if you have a question, you will need to press star 1 on your telephone. To withdraw your question, simply press the pound or hash key. Please stand by while we compile the Q&A roster. Our first question is from Don McIntosh with Johnson Rice. Please go ahead.

Morning, Jay. Rolling around. Morning. Just wanted to... Get a little more color on the back half of the year. You know, you all are pretty clear about looking to push completions out and try to capture a higher gas price. But, you know, CapEx is fairly flat. So thinking, you know, along the lines of you're spending this year to bring volumes on next year, just kind of how are you all thinking about the trajectory for 2021 and, you know, balancing cash flow and CapEx?

Well, you know, what we do, we kind of mentioned this, we're going to look at this free cash flow low number of 150 to 200 million 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, you know, 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's where that 64% comes in. But, you know, 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. 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, and we've said this two or three 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, and 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 enviable position. Does that answer your question?

Yeah, and, Don, maybe to add to that, I think as you look today at all those factors that Jay went over, I mean, we're looking toward kind of a, we think a six-operated rig program fits all those parameters right now. Now, things could be different, you know, three months from now, and so we might have a different answer. And that's one reason the operations group has planned to, by the end of the year, kind of 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 or 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 everything seems to be aligning up to that type of year next year.

Well, you know, a lot of the noise and the numbers, I mean, you've got the denim Series A preferred. We needed to get that noise out of the numbers as far as shares. We needed, you know, we said that we did stretch on the use of the RBLs, 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 liquidity. And then you can see, even in a very stressed quarter, you know, we've made almost $2 million, and it's a pretty hard quarter to have free cash flow, one, and to have any profits, two. And you can see we are committed to hedging because we need to be hedged, whether it's We're at the top there. We should have a risk program for hedging. We'll start out with six regs. We'll probably keep those six regs for 2022 right now. That's our goal. We can change it. We changed that in the fourth quarter of 2019. We had nine regs. Of course, in January of 2020, we had six. We dropped down to five, four. We ended up at four. So we definitely can toggle that. Most of these great contracts are well-to-well-to-well. And again, as you see the service costs collapsing because the service companies are really in a fatigued position with these low prices, we should get these costs per foot down like Dan had said. We're probably $1,400, $1,500 in 2018, 2019. 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 and June the market trusted us with the bond offering and the equity offering.

And, Don, I think that this quarter, like Jay phrased at the very beginning, you know, you really stress-tested the whole company, you know, 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 our cost is fundamentally low. We still achieved an EBITDAX margin of 73%, probably the highest of any companies we track in the entire industry. And even if you strip the hedges away, we still had a 60% margin, even if you just 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, you know, a simple analogy, everybody went behind the curtain on a Wizard of Oz to see what you're made of, and we look pretty good.

Yeah, 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. Just for a quick follow-up, You all have made a lot of progress on the balance sheet, and congrats on getting off two deals. And, you know, as I said, it was a really challenging environment for 2Q. You know, ultimately, you talk about a long-term leverage target of, you know, under two times. What are some of the other levers you all could pull over, you know, to potentially expedite that deleveraging? And, I mean, like I said, what you got done is, you know, remarkable in the second quarter. But, you know, is there anything else you could look to do in the capital markets or maybe, you know, M&A still an option for deal averaging? What are you seeing on that front?

Well, you know, on the M&A front, we are trying to position ourselves to be the funnel for companies that would like to have a transaction in the Hainesville-Bossier area. Now, you know, the markers that we set 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 deliver the company, period. I mean, that's just we don't have to do anything right now. We're in really good shape. You know, we would like to continue to grow if that opportunity is there. But, you know, 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 will be some decisions that, you know, we'll make and the board and the Joneses will make. about whether we want to grow or not. In fact, you know, we're always in discussions with the opportunities that are out there. And I 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. They know us.

I think, Don, if we just stick to our basic plan here and stick to our knitting, you know, we look ahead and just based on today's, you know, commodity prices that are out there for the future, you know, by 2022, you know, we're under 2.5 times leverage. 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 our plan, you know, will achieve our leverage goal.

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

All right, great. Thanks, y'all. Thank you for the call. Sorry, thank you for the call. Thank you. I look forward to following along.

Yes, sir. 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 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?

Yeah, that's a great question. I think I think the Hainesville itself is kind of undiscovered. You know, everybody's had their 2020 vision on the Appalachian, and nobody has been asked to be educated on the Hainesville-Bossier. I think there's a select group of analysts, and you're one of them, that, you know, you took your binoculars closer to the Gulf of Mexico, close to Mexico, close to the LNG, close to Industrial Corridor, close to where the midstream pipelines are. 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 Hainesville. So, one, I think it's education. I don't think that we've exposed the Hainesville properly because it's in its infancy. So I think, two, Appalachian, you've got, you know, six, seven, eight, ten companies there that are public. You don't have education. that type of landscape in Hainesville. I mean, we sell more Hainesville Bozer 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 Hainesville. So I think education. One, I think execution. You know, 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? 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, yeah, I think over and over and over, kind of like we had to do with you, you've got to say, prove it. You know, a lot of these companies say, well, we actually have proven it, and particularly in the second quarter when the end of the wheel fell off a lot of these companies, a lot of Chapter 11s, a lot of misery, a lot of pain, a lot of impairments. I think that tells you our top cards are really, really well set. But we just need to get out and broadcast it. And, again, you know, we did need more float. So we, you know, we, I think the Joneses said, okay, I'll issue shares at $5 as a company and a reason that, And, you know, 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. You know, when denim initially got their 26, 27, 28 billion 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 floats. 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. You know, it's 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. You know, I look at our bonds. If you all bought bonds – And you bought them at 90 cents, whatever. I mean, they're trading at 101, 102 yesterday. You've made money. If you bought equity at $5, it's six and change. You made money. You know, we're making money for all these people, period. And then we're protecting those that are our base, you know, 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's got to deliver on the cost. He's got to be real efficient on operations. You know, we brought Ron Mills over here. We didn't have really someone that was that connected with the hand list 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've 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 after we get lower cost of funds. So I hope that answers your question.

Yes, absolutely it does. You mentioned the Hainesville landscape. I know I asked you last quarter about just big picture thoughts on industry consolidation in the Hainesville. Maybe I'll ask it again, especially now that, you know, Chet speaks in the process of the prepackaged Chapter 11.

Well, you know, we, number one, let me tell you how we look at acquisitions. First of all, we look at rock quality. And I do think we understand rock quality. We're listening to 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&A group and David Terry leads that, and he's fabulous, and he was a leader at Covey. I think that's where Dave 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? You know, what kind of farm transportation commitments do you have? So we've looked at all of those and most of those companies, including Chesapeake. 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. We look at them with open eyes, and, you know, if we can become better, they can become better, and we deliver and everybody's happy, then, you know, 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 – pulled out a billion dollars 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, you know, 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 between And 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 Cassie Harrington with Siemens Energy. Please go ahead.

Good morning, everyone, and thank you for taking my questions. So in the prior presentation, you know, there was some commentary on how a portion of the improvement in DNC costs was driven by reductions in completion intensity. And, you know, we can clearly see, you know, the benefit of that as, you know, 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, you know, based on the early data that you guys are looking at, how to think about, you know, the impact of near-term productivity and from the lower completion intensity designs.

This is Dan. We are continuing to monitor the performance on those wells. It's pretty hard to extrapolate out a really good EUR 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 wells relatively downsized jobs to what we were getting on the larger jobs, and where we have the infilled locations and the co-developed locations where we complete three or four 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. 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 first quarter. I think we're starting to see some benefits 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 ducts at the end of Q2 – And if you just look at our drill cost, you know, we're down 10% to 15% there since Q1. So I think, you know, that along with just holding the completion cost flat, you know, we're going to get to that 1,000 bucks or probably below per foot. And, you know, that's with service costs staying the same. You know, I thought we'd reach the bottom of the barrel in Q1. I mean, you know, who saw this whole COVID pandemic coming? That's obviously put more stress. on the pressure poppers. And so we've, you know, we've seen another step down in service costs, frack costs, basically, from Q1 and, you know, to the end of Q2 and going into Q3. So that was a little bit unexpected. You know, we kind of had these cost targets in place really before that hit. So, you know, that will, you know, help us maintain the $1,000 a foot.

That's helpful and good to know that it's still an MPU project. NPV positive decision. And then I guess, you know, this is a good segue into my next question. You know, at the six-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, you know, based on what you know today. Okay.

Yeah, I think if you're looking at that program and the, you know, just timing of when those wells get completed, et cetera, you know, I think we're targeting CapEx, you know, for next year, you know, probably in the, you know, probably kind of similar levels to this year, maybe slightly higher, probably the 450 to 475 million dollar area. I mean, I think that's going to be kind of the overall cost of that program.

You could use that 450 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? Yeah.

Yeah, that's good. That's good, and that incorporates basically on average at least one incremental rig, plus or minus one incremental rig versus what we're going to average this year.

And remember, we'll have two FRAC crews, and we'll toggle a third FRAC crew every now and then, so we don't have probably more than – 15 ducks at any given time.

And that would be bringing more wells to sales. We'll have kind of that 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 drilling complete costs that we can achieve. the expected commodity prices, it really sets up for a really good 21 combination of all those factors.

You know, 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, you know, 50-50 Comstock, Covey, maybe a little more toward Comstock locations than Covey. And we drill north, south, east, and west 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. I mean, it's where we've drilled everywhere. That's important.

I'd like to throw all your wealth in maybe Elm Grove and the very top of our inventory, but that 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. I mean, a lot of the program planning is around how do you efficiently bring the wells on, minimize, you know, downtime, create kind of an overall best kind of result. And we use the entire field, you know, to achieve that. So, you know, 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, you know, push any area too hard at one time.

So I think I'll – I think when you look at those numbers, again, there hasn't been a management group, which includes company and comp stock, that's drilled and completed more of these extended lateral and completed wells than we have. That's at 237. So we've, you know, we've got a lot of experience here.

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

Yeah, great question.

Thank you. Our next question comes from Wells Fitzpatrick with Truist. Please go ahead.

Hey, good morning.

Morning.

Do you guys have any early indications as to second half non-op spend and 21 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 had initially thought.

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

You came on strong and we muted you a little bit. Now we've 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 spending.

Oh, okay, yeah, non-op for Comstock. Yeah, 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, you know, they – you know, they would be circulating the 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, you know, for the remainder of the year is in the, what, $15 million area, $15 million. $18 million of total spend for the next six months.

Okay, perfect.

Yeah, the acreage trades, that's part of that. You know, those actually help. I think some of the stuff we actually spent money for in the first quarter, we end up doing an exchange with. And so I think that's always the goal of the operators. You know, 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 in the second quarter. It kind of helped the overall location count get a little longer. I think we increased our percentage of long laterals. It also helps eliminate what we like, too, is eliminating some of that non-op spend.

The beauty of the story, and you asked the non-op side, but The beauty is, you know, 92% of our production we operate, and, you know, we've got, what, 95% HPP. So it's a non-op, and we do budget some of that, but we're not seeing, you know, any radical non-op operator out there, building wells that, you know, are maybe iffy. We don't see any of that happening right now. Good.

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 six 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 it be a month for kind of five or six months? I mean, was there anything different in the completion or the flow back on that?

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 1 area, that, you know, that system has stayed relatively full. So – Here and there in some wells, you know, we're a little bit limited as far as maybe getting an absolute max out of them. But this well in particular, the George Mills, you know, we IP'd that well at about 35 or 36 million a day. And so essentially that rate, we stayed in that 30 to 35 range for several months. You know, I need to look at it in detail to give you the exact, but that's, you know, 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 Cocker and Palmer. Your line is open. Good morning. Good morning.

You know, I hopped on a little late, so sorry if something you touched on.

Uh-oh, we'll re-pantelize on you.

Oh, okay. I was going to say, we talk about your improvement in the well cost per foot. You're bringing it from $1,400, $1,500 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 challenge is still remaining to drive it down further. You seem to have pretty good confidence that you can go lower still.

Yeah, so, you know, we've basically been on a downward trend for several quarters now. That's pretty much been driven by, you know, our drilling costs have been, you know, relatively and fairly unchanged during that trend. So, really, that was pretty much almost entirely driven by, you know, the On the completion side, mainly the frac costs, I mean, just the frac costs we've seen for several quarters, you know, just the provider cost, I mean, has really, you know, plummeted since back in probably mid-2018 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 first quarter, like I said earlier, but – I think we're probably there now. I just don't see the frack 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. You know, really, from this point forward, as far as getting that cost down a little bit further, it's just really in efficiencies. I mean, we have gone to the downsized frack job. That's obviously part of the answer. We'll continue to monitor performance on those, make sure, you know, 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 effect. So a little piece of that will be the frack cost because, like I said, it did step down again from Q1 just with the entire COVID-19 pandemic just kind of basically destroying the demand, the activities, you know, the rig counts drop, activities drop. But aside from that, it's just getting better at what we do. It's... It's saving a couple of days drilling the wells. It's a couple of days less fracking 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 extra efficiencies are.

Great. Thanks. 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 a conventional play at this point, just given your inventory you already have in the Hainesville?

You know, 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 with what got us here, and so if we commented on that, we'd probably be out of our court. And the other color I'd like to add with Dan on your first question, remember, he's been here since 2008, so every single well that we've ever touched in the rainfall 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, You know, 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 to give you those answers. I think that's important. So a little detail there.

Thank you. I'll just add to that. I mean, we've got a pretty good staff here, and obviously, you know, we've got a lot of experienced people on our staff in Ninesville. I mean, that's what creates, you know, the numbers that you see.

In fact, if we were to open a lineup to them, they could all give you their own answer, but it would take too long.

Okay. Well, I look forward to some other time. Thanks so much. Thanks for your time. You bet. Thank you, Noel.

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. Again, time, I think, is the most valuable thing we all have. And so we're 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 are very excited about what the next 18 months could bring to the company. So thanks 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.