Comstock Resources, Inc.

Ladies and gentlemen, thank you for standing by, and welcome to the third quarter 2020 Comstock Resources Incorporated Earnings Conference call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you'll need to press star 1 on your telephone. As a reminder, today's program may be recorded. I would now like to introduce your host for today's program, Mr. Jay Allison, Chairman and Chief Executive Officer. Please go ahead, sir.

Thank you. Thank you for your introduction this morning. And, again, I want to thank everybody that's taken their time to listen to the story today. I know we have a lot of you we know. A lot of you are really good friends and have been forever and ever and ever. So today is an important day in our corporate life. We're all human, and we do understand the third quarter results are somewhat disappointing, quite frankly. And I can speak for me and for everybody else in the management team, we hate it. And, you know, they are disappointing for the reasons that you're aware of. I mean, they're all logical reasons. They're still disappointing. Shut-ins, curtailments related to Hurricane Laura, non-op curtailments, and there's a litany of other small reasons. You know, I think our goal this morning is to share what we see. for the fourth quarter of 2020, as well as 2021 and 2022, and to show you, our stakeholders, how we plan to deliver our balance sheet in those years by using our strength of our peer-leading high margins and low costs that we've created in the Hainesville in a period of time, quite frankly, when the outlook for natural gas is extremely bullish, really the most bullish it has been in over 10 years. Our job in the next 45 minutes really today is to avoid any disappointments in the future and show you how our high margins in the Hainesville coupled with the right size capital program over the next years can deliver the balance sheet and expand our trading multiples so that we all are winners, all based on the commodity gas price outlook that we see today. So thank you for trusting us, and if we have dented – that trust any, please know that the entire Comstock team will work hard to earn it back and even more by giving you 100% of our best as we always have. So now I'll start into our third quarter results and then we'll get to the Q&A and we'll answer any question that you have and be accountable for it. Welcome to the Comstock Resources Third 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 entitled Third Quarter 2020 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer. Dan Harrison, our Chief Operating Officer. and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentation to note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you're following this, you can turn to slide three. On slide three, we discussed the highlights of the third quarter. November is the first month where we finally exited the period of very low natural gas prices brought on by the warm winter we had as the November natural gas price closed at almost $3 after hitting a low of $1.50 this summer. The low production levels brought on by the actions of disciplined natural gas producers combined with the decline in associated gas resulting from low oil prices have caused the 2021 future natural gas prices to improve substantially. Since January this year, we have been focused on reducing our drilling activity and deferring completion activity. Those actions allowed us to generate free cash flow even with the very, very low prices we're receiving for our production. The reduced activity we had in the first half of the year combined with the third quarter hurricane activity in our region negatively impacted our production this quarter, as you see. With the stage set for higher prices later this year and into 2021, we collectively decided that we would go back to work in the third quarter. We added two additional operated drilling rigs to bring our working rigs back up to six, which is where we were at the beginning of the year, and currently have three frack crews working to catch up on the backlog of drilled and uncompleted wells. Since our last report, we have put 15 new wells on production, which have a per-well IP rate of 26 million cubic feet per day. We did have a rocky quarter, as I mentioned, on the production front, which partially was self-inflicted as a ramp-up of activity drove our shut-in percentage up to 7 percent in a quarter. The higher spending in the quarter reflects restarting a program we put on hold in the second quarter, but it is the right move as we look forward to improved gas prices that we're in. We did achieve our goal of reducing well cost to just under $1,000 per lateral foot, which is significantly lower than any other Haynesville operator. With recent changes to our completion design, we expect well cost to increase a little bit, as Dan Harrison will go over later. While it made sense to bring well costs down as low as we did with wheat gas prices this year, with gas prices closer to $3 plus now, it makes sense to invest in a little more profit as we believe the wells will have a higher return. As we will discuss more today, the wells will have a higher return. As we will discuss more today, we recently decided to increase our completion activity plan in the fourth quarter by running an additional freight crew. which moves up the completion of seven wells that we plan to complete in 2021. The additional investment will pay off in 2021 to allow us to have a little higher production to take advantage of the higher gas prices. In the third quarter, we completed a follow-on $300 million notes offering to further pay down borrowings on our bank credit facility. We reduced our outstanding bank borrowings from 57% of availability to just 36% of our availability. By freeing up the bank credit facility, we increased our financial liquidity to $928 million. The low oil and natural gas prices combined with low production in the quarter did impact the profits we generated in the quarter. Our oil and gas sales, including hedges, were $212 million. Our adjusted EBITDAX came in at $148 million, and our operating cash flow was $93 million, or 38 cents per share. We reported an adjusted net loss of 13.8 million, or 6 cents a share. With higher production and stronger natural gas prices, we anticipate returning to profitability in the fourth quarter, which is now. I will have Roland go over the financial results in more detail. Roland?

All right. Thanks, Jay. On slide four, we summarize our financial results for the third quarter of this year. Our production for the third quarter totaled 103 BCF of natural gas and 354,000 barrels of oil. Total production of 105 BCFE was 4% higher than the third quarter of 2019. Our oil and gas sales, including the realized hedging gains, were $212 million, which was 15% lower than 2019. And this was all driven by the lower oil and gas prices we had in the quarter. Oil prices in the quarter averaged $33.52 per barrel, and that's with the hedging gains we had in the quarter. And our realized gas price, including hedging gains, was $1.95 per MCF. Our natural gas price realization overall was down 14 percent, which offset the production growth that we had in the quarter. Adjusted EBITDAX came in at $148 million, which was about 22% lower than the third quarter of 2019, and operating cash flow of $93 million was about 35% lower. We did report a net loss of $130.9 million for the third quarter, or 57 cents per share, but most of that loss is attributable to the $155.6 million unrealized loss on the mark-to-market of our hedge positions, and that is all caused by the substantial improvement to future natural gas prices since the end of the second quarter. Our adjusted net income, excluding the unrealized mark-to-market hedging loss and then certain other unusual items, was a loss of $13.8 million, or six cents per diluted share, for the quarter. Slide five, we summarize our financial results for the first nine months of this year. Production for the first nine months totaled 349 BCFE, including about 1.2 million barrels of oil, which is 90% higher than our production for the same period in 2019. Of course, most of this increase is due to the acquisition of Covey Park Energy, which we completed in July of 2019. Oil and gas sales, including realized hedge gains were $716 million, 40 percent higher than the same period in 2019. Oil prices so far this year have averaged $39.84 per barrel, and our gas price is $1.96 per MCF, both including the hedging gains we had. Overall, this is 18 percent lower than the prices we had for natural gas in the same period in 2019. Our adjusted EVA DAX came in at $511 million, which was 35% higher than 2019. Operating cash flow was $367 million, and that's 31% higher than 2019. We did report a net loss of $160.9 million for the first nine months of this year, or 77 cents per share. Again, this was due to the mark-to-market loss, the unrealized mark-to-market loss on our hedge book. Mark-to-market loss. loss, the unrealized marked market loss on our hedge book. Adjusted net income, excluding the unrealized hedging losses and other usual items, was $12.9 million, or a net income of six cents per diluted share. Third quarter production was adversely impacted by a higher shut-in level than normal, as you can see on slide six. Seven percent of our natural gas production was shut in in the third quarter, as compared to 4% in the second quarter. Much of that shut-in is due to offset frac activity, either by our simultaneous operations or other Hainesville operators. But we also temporarily shut-in a portion of our production over the course of about a week due to the impact of Hurricane Laura that caused widespread power outages in our region. And then also in September, for a good part of the month of September, and then carrying over really into the first, you know, 12 to 14 days or so of October, we did experience wide differentials in the daily cash market at Perryville and in other indexes in our kind of region in the southern kind of Gulf region. And this was all due to concerns that the natural gas market had over the high storage levels as we exit the period of storage injections. So the only gas that's really impacted by these daily prices is what we call our swing natural gas that was not sold during bid week and is not part of our base load sales. So we chose to restrict some of the new wells that were coming on in September and then given this very low price that this extra swing gas was getting. And these high differentials in the month of September and also the declining overall index prices in that volatile month did cause our overall differential in the quarter to widen by 10 cents in the third quarter. This situation did continue into October, really only the first couple of weeks of October. And then we took an action in the very first part of October to actually curtail, for price reasons, $300 million a day of our production. And overall, we did this for about 11 days. That action, along with the startup of LNG facilities, coming back after the hurricanes, really helped reduce the concerns about storage filling up. And then we saw... Now, about mid-October, we saw the daily cash prices go back into a normal relationship and differentials narrow, and then we put all that gas, you know, really back into the market. So I think as October has finished out and as we enter November, we've seen a very healthy situation, which has been supported by – you know, very favorable kind of injections to storage and even today a withdrawal. We also saw that, you know, obviously our non-operated oil production, which is primarily located in the Balkan region, also has continued to experience substantial curtailments, which carried through in the third quarter. We had about 12% of our oil production that was shut in by the operators that operate it due to the very low oil prices or other issues in the Balkan region. On slide seven, we cover our hedging program. For the first nine months of this year, we had 50% of our gas volume hedged, which increased our realized gas price to $1.96 per MCFE from the $1.60 that we actually received from selling our production. We also had 86% of our oil volumes hedged, which increased our realized oil price to $39.84 versus the $30.35 per barrel that we actually received. Overall, during that period, we had realized head gains of $133 million. But with the improvement in future natural gas prices, we also took that opportunity to continue to add to our hedge book, but really at higher levels than we'd hedged before, and then also using collars. So we've added about $10 million a day of natural gas for the fourth quarter since we last reported earnings, and we added about $38 million a day of natural gas collars in 2021 and about 12 million a day of collars in 2022, which gives us a good protection level but also gives us exposure to the higher prices. As you look ahead for the fourth quarter of 2020, we have 663 million cubic feet of our gas and about 2,800 barrels per day of our oil hedged. The weighted average floor price of our remaining 2020 gas prices is $2.61. And for 2021, we have natural gas hedges covering about 836 million cubic feet of our 2021 production. So we're on target to having 60% to 70% of our 2021 production hedged, and we'll also work as we have this improving gas strip to work with, to hedge our 2022 volumes appropriately. On slide eight, we detail our operating costs per MCFE produced. And overall, these were pretty comparable to the second quarter. So our operating costs averaged 55 cents in the third quarter as compared to our second quarter rate of 54 cents. Gathering costs were 21 cents. Production ad valorem taxes averaged $0.09, and field level costs were $0.25. The one thing we did do this quarter in order to improve the comparability to us and other producers was to reclass our ad valorem taxes that used to be showed as part of just lifting costs and include those in production taxes. So you'll see that if you're kind of tracking the old numbers. And so it's really about $0.01. So not a big change, but we think that just makes us more comparable to our peers. On slide 9, we detail our corporate overhead for MCFE, and our cash G&A costs were $0.07 in the third quarter, which is slightly up in the second quarter, but that's mainly due to the lower production level in the quarter. On slide 10, we detail the depreciation, depletion, and amortization per MCFE produced. Our DD&A averaged 95 cents in the third quarter, which was about 8 cents higher than the second quarter. And then most of that impact is due to the much lower kind of SEC-type prices that are kind of backward-looking that we used to do amortization with. On slide 11, we recap our third quarter and the first nine months of 2020 capital expenditure program. So we spent $110 million on development activities in the third quarter, and $94 million of that was related to our operated Hainesville shale properties. For all of 2020 so far, we spent $316 million, including $259 million on the operated Hainesville properties. We've drilled 36 or 28.6 net operated horizontal Hainesville wells so far this year. and we also completed 9.6 net wells that we drilled in 2019. We've spent $56 million on non-operated activity and for other activity so far this year. We generated $367 million in cash flow for the first nine months of this year, resulting in free cash flow of $30 million after we paid the dividends on the preferred shares. After dropping our operating rig count to four rigs in April, which was down from six back in January, we've increased our operator rig count back to six rigs. In the fourth quarter, we expect to spend about $150 to $170 million this year to drill 17 or 16.4 net operated Hainesville wells, and then to turn to sales 22 or 17.6 net Hainesville wells. We made the decision recently to keep a third frat crew busy in the fourth quarter, which we originally planned to release and then bring back, you know, in early 2020. This does add about $30 million to our 2020 spending, and the reason for it was to accelerate the completion of seven wells before we planned to complete in 2021. And this is in order to take advantage of the higher gas prices, especially that, you know, we see for the first quarter of 2021. And it was just a decision based on if we kept our original schedule, We compared that to keeping this third rig, which was performing well for us, and operations asked us to look at that. And we said, you know, we actually make $15 million more by accelerating that completion into kind of the prime, the highest gas price months on the futures curve. And so we said that's the right thing to do. If you look at the full year for 2020, if you combine the fourth quarter with that, we now expect to spend about $450 to $500 million this year, which would have drilled 53 or 45 net operated Hainesville wells this year, which would have drilled 53 or 45 net operated Hainesville wells and turned 55 or 42.2 net operated Hainesville wells to sales. We also participated. We also plan to participate in 18 or 1.3 net non-operated Hainesville wells and, in turn, 3.8 net wells to sales. At the end of this year, we now expect to have about 16 or 15.4 net ducts or drilled and uncompleted wells. So as you look ahead to 2021... We expect to increase spending a little bit over the 2020 level in response to these higher natural gas prices that we see. And we expect to spend between $525 to $575 million and drill 70 or 56.5 net operated Hainesville wells and turn 65 of those wells or 56.6 net wells to sales in the year. Our initial plans right now are to add a seventh operated rig, and we would do that in the second quarter of next year. Obviously, as we get to that point, we'll assess, you know, the natural gas market in our region and decide if that's still a great course of action. If not, as we've shown in the past, we don't have long-term commitments for drilling or completion services or any kind of volumes to meet. So it's clearly an economic decision on when we spend the CapEx and what And we can react, as we did this year, we can react to the market and adjust our level of spending as is appropriate. But we still remain focused on generating significant free cash flow, and we see next year as having a bounty of that, you know, with the plans we have. And we target to have a minimum of at least $200 million of free cash flow as we plan for any future capital spending. On slide 12, we show our balance sheet at the end of the third quarter, and during the third quarter, as Jay mentioned, we issued $300 million of new unsecured notes to term out a portion of the borrowings outstanding under our credit facility. So we ended the quarter with about $500 million drawn on our credit facility, and we do expect to continue to pay that down with free cash flow generated during the rest of 2020 and into 2021. Okay. With a quarter-ending cash position of $28 million, our current liquidity now stands at $928 million. We have just over $2.25 billion of senior notes outstanding, and that's comprised of $619 million of our 7.5% senior notes due in 2025 and $1.65 billion of our 9.75% senior notes due in 2026. So I'll now turn it over to Dan to cover the third quarter drilling results in more detail.

Okay, thanks, Roland. Over on slide 13, this is just our updated outline of our current acreage position, which has increased this quarter up to 309,000 net acres. We control the majority of the acreage with a 91% operated position and have an average working interest in the acreage of 81%. We currently have 1,943 net future drilling locations identified on the acreage, with 96 percent of the acreage is currently held by production. Since resuming our completion program at the very end of June, we have turned 15 additional wells to sales. This now brings our total DNC count up to 252 wells since early 2015. Like Roland mentioned, we have added two additional rigs since our last call, and we're now running a total of six rigs. Due to the break in the frack activity in Q2, we started out the third quarter with a total of 21 ducts. We've since worked that down to 16 wells currently. Our go-forward duct count should remain roughly at this level through year-end and into next year. We started out the quarter with two frack crews. We ramped up to three frack crews in early September, and we will continue to run these three frack crews through the end of the year. Based on our current six-rig schedule to seven rigs next year, we anticipate running on average 2.4 frack crews in 2021. Over on slide 14, this is our latest Hainesville-Bossier atomized drilling inventory at the end of the third quarter. Our gross operated inventory currently stands at 2,401 locations with our net operated inventory at 1,761 locations with our net operated inventory at 1,763 locations. This represents a 73% average working interest on our operated inventory. Our non-operated inventory is at 1,352 gross locations with the net non-operated inventory at 180 wells And this represents a 13% average working interest. For the gross operated inventory, we have 494 short laterals and 905 medium laterals and 1,002 long laterals. Breaking this down by the gross operated inventory by zone, we have 54% of our locations are in the Hainesville and 46% are in the Bossier. We are focused on converting our short laterals to long laterals. While the total number of locations has not grown, the number of 8,000-foot and longer Hainesville laterals has increased to 420, up from 389 at the end of the second quarter. This inventory provides the company with over 30 years of drilling locations, both in our current activity levels. Slide 15 is a map outline and summary of the 15 new wells that we've turned to sales since the last call. The new wells were spread out fairly evenly across our Greenwood-Wascombe, our Logansport, and Elm Grove acreage. The wells were tested at rates of 16 million a day to 35 million a day, with a 26 million per day average IP. The wells were drilled with lateral lengths ranging from 6,049 feet up to 9,869 feet, and we averaged 9,088 feet for the quarter. All of these completions were completed with 2,800 pounds per foot. As mentioned earlier, we have three factories working today, and we'll maintain that level of completion activity through the end of the year. The current duct count, as before, stands at 16, and that should maintain through the end of this year and into next year also. Slide 16 is a chart. This illustrates the progress we continue to make driving down our DNC costs. These results track only our medium to long-term laterals, which have the lateral lengths of greater than 7,000 feet. Our DNC costs continue to trend down in the third quarter and are starting to flatten. We again achieved our lowest all-in DNC cost to date at $998 a foot. Contributing to this low DNC cost were two record low-cost wells that averaged less than $900 a foot. This DNC cost is 17% lower than the same quarter a year ago, and it represents a 2% cost reduction from the previous quarter. The story is really the same. Our current service cost, coupled with our really high completion efficiency and the smaller jobs, has really been the driver for the low cost. Since the last call, we've generated enough production history on the earliest wells completed with the reduced frack intensity to evaluate performance. We have observed a slight reduction in our EURs, which we expected to a small degree, which made sense, you know, with the low gas price environment we were in earlier in the year. Starting in September, we have shifted back up to our original job size in the 35 to 3,600 pound per foot range as we have entered a much better gas market. Based on our most recent well costs, we're still aiming to keep our costs relatively flat. in the 1,000 and 1,050-foot range. Going forward, the market demand on services will play a large part in our cost structure. With that being said, we do believe our current cost structure will maintain through the end of the year, but we acknowledge that us and the rest of the industry may be facing some upward pricing pressure in 2021. That kind of recaps the operations. I'm now going to turn it back over to Jay for some final comments.

Okay, thank you, Dan, and also, Roland, thank you. If everybody would go to slide 17, I'll go over this slide and then turn it over to Ron for some guidance. I'd like to direct you to slide 17 where we summarize our outlook for the rest of this year and our initial thoughts on next year. You know, for the first half of this year, we've remained primarily focused on pre-cash flood generation and managing the company through the low oil and natural gas price environment we've been in. While natural gas prices remain relatively low, Through October, due to elevated levels of gas and storage, the outlook for natural gas has improved substantially for late 2020 and 2021, driven by expectations for significant declines in natural gas supply due to continued reduction in natural gas-directed drilling and completion activity and less associated gas production from related activity in oil basins, resulting from limited gas production from related activity in oil basins resulting from the collapse of oil prices. You know, starting in the third quarter, we went back to work and resumed completion operations with refrag crews in order to work through the backlog of ducts that Dan had talked about. And we've added two additional drilling rigs to generate production growth late this year, and more importantly, in 2021, to coincide with improved natural gas prices. You know, we also recently made the decision to accelerate well completions originally planned in 2021. We're keeping a third FRAC crew working in the fourth quarter, which moves about $30 million to our 2020 budget from 2021 in order to complete seven wells three months earlier. The rationale is that we can produce the gas related to these wells earlier in 2021 in the higher gas price months. The strength that we lean on this year is our industry-leading low-cost structure and well economics. You know, with all our focus on reducing activity and delaying startup for the new wells, we expect to have about a 2% pro forma production growth this year. Next year, we expect a balanced growth of probably 6% to 8% while generating substantial free cash flow that we'll use to pay down our debt and reduce our financial leverage. You know, we've hedged almost half of our production over the remainder of 2020 and 64% of our 2021 production and have strong financial liquidity of $928 million following our recent bond offering. So with that, now we'll turn it over to Ron to provide some specific guidance for the rest of the year.

Ron? Thanks, Jay. On slide 18, we provide financial guidance for the fourth quarter of 2020 and our initial guidance for 2021. This guidance reflects the impact of the timing of our drilling and completion schedule as well as the shut-ins discussed earlier in this call. For the fourth quarter, we anticipate spending $150 to $170 million on our drilling and completion activities, which will result in 2020 total spending being $450 to $500 million. That's higher than we discussed in the second quarter call due to laterals getting longer some additional work over activity, some non-operated activity, and some minor leasing costs. Fourth quarter 20, production is expected to average 1.15 to 1.25 BCFE per day, and our 2020 production is expected to average at the low end of our prior guidance of 1.25 to 1.3 BCF a day, despite the impact of the shut-ins and the hurricane impacts previously discussed. Looking ahead to next year, we're providing initial CapEx guidance of $525 to $575 million and production guidance of 1.325 to 1.425 BCF a day, which anticipates the addition of the seventh rig by the middle part of next year. LOE is expected to average $0.21 to $0.25. Gathering and transportation costs are expected to average $0.23 to $0.27. The production and ad valorem taxes are expected to average $0.08 to $0.10. Our DD&A rate is expected to be $0.90 to $1, and the cash E&A is expected to be in the $0.05 to $0.07 range on a unit basis. For the rest of the call, we'll turn it over for questions and answers.

Certainly. Ladies and gentlemen, if you have a question at this time, please press star then one. Our first question comes from the line of Derek Whitfield from Stifel. Your question, please.

Thanks, and good morning, all. Good morning. All right. With regard to the 2021 outlook, would it be fair to assume you'll see minimal production from the seventh rate you're adding in 2021 and the real impact will be felt in 2022 where that activity increase could sustain growth in that call it 6% to 8% range?

Yes, this is Roland. That's a good observation. I think really if you look at the way that shale companies, especially how we're developing the shale, the capital that we spend today really doesn't generate production until four to six months later because we always drill on pads just because it increases the drilling efficiency so much. So you have two to three wells kind of waiting before they come online. So And given that we're looking at, I think as we look ahead into 2022, you know, we wanted to create some guidance that even though it didn't add a lot of production to 21, that even though it didn't add a lot of production to 21, and probably the action we did to actually spend additional dollars in the fourth quarter, probably has a great impact on 21. But adding an extra rig, you know, really doesn't – there really isn't a lot of production that gets on in time to really move the numbers. But what it does, I think we have a – we've set the stage for a very sustainable program into 2022 versus having a higher growth rate in 21 and then going back to hardly any growth in 22. So I think that given the outlook for gas and the companies kind of exiting this period of very low gas prices and be very defensive. We wanted to set kind of a more sustainable program out there that makes sense for the overall achievement of our goals, which is to, you know, get leverage below two and use the strength, like Jay pointed out, of the very high margins that these wells can generate in this gas price environment. We do – we're sensitive to the fact that the market doesn't like, you know – additional spending and growth, but I think if you focus really on that we're a natural gas company and the outlook is so much stronger next year, it's not the same case as a oil company that's looking at a more uncertain commodity and not a favorable kind of future. So I think we think it's the best action for the company. It's how we achieve our goals, and it also sets expectations into something that we think we can really outperform next year and also outperform in 2022, and that it's not overly short-term focused on just, you know, getting the maximum results next year?

Well, again, our goal is to, you know, figure out on a quarterly basis how we should spend our capital dollars. That's why we've looked at 2021 commodity prices. We've looked at, you know, fourth quarter 2020, and we said we We should keep AFRAC crew busy. We should lean into 2021 because, again, if you look at the advantage we have, I mean, we have advantage access to the demand market of the Gulf Coast. We're favorably exposed to Henry Hub. I mean, so when we look at that, we need to lean into that market that we have. And you see the LNG exports, I mean, they're at an all-time high right now. We think where the weather, where it is, and where commodity prices really are, where our leverage, where it is, and our low cost. I mean, Dan has given us low costs and high margins. We've got to give you an outlook for the fourth quarter as well as 21-22 so we don't have any disappointing quarterly results to you again, period. That's what we're doing today. We're correcting everything.

Thanks, General, and that certainly makes sense. And as my follow-up, referencing slide six, you guys were clearly impacted by several uncontrollable events in Q3. As you look out to Q4 and then into 2021, how do you envision that shut-in metric trending over that period?

Yeah, that's a good question. I mean, you know, a large impact is always the simultaneous operations, which is, you know – happens now because we do, you have to protect your offset production from offset frack activity either we created or one of our neighbors creates it. So, yeah, I think it's, you know, it's probably, you know, realistically, you know, a 5% number, you know, pretty flat. I mean, especially if we keep a more consistent program, I think it stays more consistent and doesn't have the kind of gyrations and, you know, that Unknown is is there power issues or pipeline issues that are caused by other events. And then, you know, I think what for the first time ever, you know, really in this late September, October period, you know, as a major producer in the Hainesville Basin, we for the first time withheld gas from the market because of the market struggling with the storage levels before it became comfortable with that level. And it's the same thing that the large producers did in Appalachia. and it's our responsibility to do that. And our actions allowed that market to recover pretty quickly and also, you know, allowed us to realize, you know, instead of realizing a very low price for the gas, to save it and then produce it, you know, a week later at a higher price. So I think we're also going to have to be mindful of that and, you know, controlling the, you know, the flow of gas, especially the swing gas that's open, you know, into a market, you know, Every year so far, you know, there has been a sensitive period for gas as it exits the injection period and storage fills up. And this October, it's been that transition now. We had it last year in October. It's been that transition now. We had it last year in 2019, but not as severe, and then this year, too. But the good news is it seems like we've made the good adjustment through it, and operators like us, you know, responded and very proactive to keeping that situation workable.

I think you won't see the impact of the private equity-backed Hainesville players, but they'll have the same type of shut-in issue. I think the good thing for Comstock, you notice we did add about 4,000 or so acres to our footprint, so we've got 309,000 acres. We do spread our drilling program out north, south, east, west, both in Texas and Louisiana. And when you, you know, when you look at our drilling program, we kind of have a pool of information from the offset operators, and we figure out when they're going to drill, when they're going to complete. And we try to toggle all of our programs around because of our large footprint to not have quite as much exposure to these shut-ins. But, again, I think, you know, Dan will tell you that it's probably 5%, I want to say 5%, and that's kind of where we are right now, even with our footprint. And, Will, you know, we put out our model and our guidance. Ron has done that. And he's kind of stuck that type of handicap in for the future.

And we didn't focus on it much, Derek, in our conversation earlier like we normally do. But, you know, we do have initiatives going on in 21 that we're going to be able to really get less and less gas sold at Perryville, which is, you know, that's more vulnerable to, especially for gas coming out of basin like it did, you know, and disrupting that basin. So... We've always had a goal of removing ourselves from that market, and I think next year, you know, there's several initiatives. The big one, obviously, is the Cadian line opening up, but we've also been working with our midstream partners to give us some other ways to bypass Perryville and move gas, you know, more to the Gulf, or at least have the flexibility to respond, you know, to that.

That's great. Extremely helpful. Thanks for your time, guys.

Yes, thank you.

Thank you. Our next question comes from the line of Don McIntosh. Your question, please.

Morning, Jay. Thanks for the help provided so far. I had a question. I understand the pickup inactivity and that attack and leverage can be a little easier from the EBITDA side sometimes. So how, you know, under this new program, where do you see leverage over, you know, 21 and 22 and, you know, targeting that We talked about two and a half times by the end of next year, but getting down under that two times, does this get you there faster? Yeah, it does.

I'll give you some numbers, I think, but we will deliver faster, and it's all because of the market demand and the prices we get at Henry Hub. No, we do deliver. You know, when we had all of our one-on-one conference calls, we said the only reason we would add a rig or complete wells earlier is if it allowed us to de-lever quicker. That's the reason you do it. So, Roland, do you have a number?

Sure. I think we get very close to getting down to our two times as we finish up 22 with this plan. And I think by investing a little bit into 21, it actually allows us to hit that goal there versus just being shy of it if we let 22 just have kind of a more of a flat production profile. Again, we're – It's been erratic for the company, obviously, to go from, you know, growing at a 34% rate, you know, back, you know, in 2019 to 2% this year is probably what it's going to end up being, you know, with all the – and then, you know, back to more sustainable levels, you know, the 6% to 8%. But we're really targeting to try to get to more of a 5% growth. To balance some growth to improve EBITDAX to get that leverage ratio down faster. At the same time, though – also reduce the overall level of debt and keep a lot of free cash flow as a big target. And, you know, the strip today gives us that opportunity to achieve all that, you know, with this program in this two-year period.

And then that gives us a growth in 2022 of, you know, maybe 5%. So what our goal today, again, it's to reset the program for the fourth quarter 20 and for 2021-2022. That's exactly it. That was a great question. It is all about delivering with where we are and the locations we have and the profits that we make.

All right. Thank you. And then for my follow-up, you mentioned in the call maybe moving to a little bigger profit. What are the kind of drivers behind that decision? Is that more of an EUR base? You know, what are the kind of drivers behind that decision? Is that more of an EUR base or is that more to bring volumes on faster at the front of the curve to kind of try to capture this higher price environment that we look like we're heading into?

Yeah, this is Dan. So, yeah, you hit on it there at that first point. I mean, it's all EUR driven, which basically is hand in hand with our performance. You know, when we So back earlier this year when we went down to these smaller jobs, we were in the lower gas prices, and we did anticipate maybe a 5% reduction in EUR, which we ran the numbers that made sense to basically test that size. We're seeing EURs more like maybe 8% to 10% smaller, and this is really for the wells maybe that are over in that state line area, the Greenwood-Wascombe area. And so when you run it at the higher gas prices, I mean, it's clearly, you know, you need to pump the bigger jobs, which also means you're pumping more water. It's just, you know, it's just a matter of the economics. I mean, the wells deliver a better PV10 value when you do that at the higher gas prices.

Yeah, I think it's a good question, too, because we intentionally, you know, we set the bookends. We look at companies that use 5,000, 6,000, 7,000 pounds of profit a week. We didn't think that would be what we needed to do. We dropped down to the lower bookends of this 24, 5, 600 pounds and water, like Dan said. And so we've kind of tested the bottom at a low gas price. And you should do that because you do save precious dollars right up front. But when you have a gas price of, you know, 293, 310, 320, and you look at the PV value and you look at how quick these wells pay out and the increased volume, it's easier to say, you know, the right thing to do is to spend a little bit more money, and we're still in that $1,000 to $1,050 per completed foot, to have a much better performance, which drives our leverage. So, you know, it's our job to tell you that, too. We didn't try to hide that. We said we should probably go back up there because we did test it, and we know what we need to do. Great question.

All right. Thank you all.

Thank you. Our next question comes in the line of Oumang Chatterjee from Goldman Sachs. Your question, please.

Hi, good morning. You mentioned that gas prices are driving your decision to grow EBITDA to meet your leverage goals. Can you philosophically talk to what would drive a shift to lower activity and spending in favor of more free cash flow? Is there a gas price point at which you will reduce activity and how has that price point evolved given recent reductions to well-cost?

Well, I think that it is definitely gas prices that are a factor in how we look at the whole picture. And obviously gas prices are not what the futures market is anticipating for 2021, and they underperform that. We would definitely reassess our spending because I think the free cash flow goal, you know, we're going to maintain it. And so I think that is definitely a big factor, and I think we – We think we've gotten, you know, overall, as the market seems to be fairly comfortable, that at least in 21 the stage is set, you know, for this $3 kind of area gas price. And we'll certainly reassess adding a rig by mid-year next year if it's not at that level anymore. So we're not at all locked in to one strategy, but we wanted to present more of – a balanced program that didn't just focus on 21 and absolutely maximize 21, which the six-week program really can do, but that comes at the expense of, you know, of 22, and you stop making the progress toward your leverage goals in 22 if you don't make any investment for it. So that was the goal of the day.

And, again, the beauty is we don't have any farm transportation obligations that cause us to drill. We don't have any minimum volume commitments that cause us to drill. Ninety-six percent of our acreage is held by production. So our CapEx budget is just driven internally by, you know, what we need to do to improve our balance sheet and pay down our debt.

And we'll be very reactive to a changing environment. So, you know, as we were this year playing defense in the first quarter, half of this year, we can be very reactive because we don't have long-term obligations that drive us to have to drill any wells at all.

Yeah, the other thing people forget, I mean, our denominator is the consistency of our wells. I mean, we have 30 years of inventory at this rate. I mean, usually people worry about the quality of your locations. Nobody ever asks us about that. People worry about the quality of your locations. Neil, nobody ever asked us about that. So we've taken that off the table. They just say, how can you de-lever? I mean, how can you de-lever? And, you know, where we are, we're the only pure or handful-sized company at this size. We say, well, again, our advantage is this access to the Gulf Coast. And we do have great gas prices. So let's use our strength. We can't act like another company in another basin. We've got to act like the company we are in our basins. And that's why we've got to tell you we're going to reset the whole program for the fourth quarter of this year in 21-22. We also tell you that whatever we need to do, if we need to shut in the swing gas because prices are low, you've now seen that we've done that. We demonstrate that we will do that. If we need to go back to lower profit, prices are lower, we'll do that. If we need to go back to higher profit, then we'll do that. Again, our goal is to be very transparent with you with as a partner as we create even a greater company.

Thank you for the call. That's really helpful. Thank you.

Yes, sir. Thank you for the time and the question.

Thank you. And as a reminder, ladies and gentlemen, if you do have a question at this time, please press star then 1. Our next question comes from the line of Kevin Kinane from Citi. Your question, please.

Hey, good morning. Just a quick one on 2021 expectations. You know, obviously, as you and a few others increase growth next year in light of higher prices, what are you looking at as far as non-op spending for the year? And, you know, are you seeing any of those private equity backed companies kind of gearing up for higher production growth next year as well?

Yeah, we don't see – you know, we have very limited touch points with other companies. So the non-op part of our, you know, portfolio has always been fairly small. And basically, we really like to do acreage trades to try to even, you know, make it smaller. And I think that we actually finished some really good acreage trades, you know, that you saw kind of come through the location numbers and acreage numbers this quarter. you know, with Geo Southern and Indigo that, you know, really improved our overall lateral length overall and reduced our non-op, you know, potential activity in the future and also actually gave us more locations in our very, very best, you know, lowest transportation cost area. So it was really a big win, and I'm sure that – we also met their goals, you know, and things they were trying to accomplish. And so, yeah, we still see non-op as a very not a big part of our budget. And frankly, if a non-op project doesn't meet our high expectations, you know, we've now got good partners that want to buy those interests. And so we're very tuned on saying, hey, if we can't generate a really good return from non-op, you know, we'll sell down the wellbore to people that are interested in investing in that. So, yeah. You know, I think we probably always have budgeted – I mean, Ron, you might say we have potentially $35 million to $40 million of non-op activity that we kind of always expect to have.

That's about right. It is typically averaged kind of in that 6% to 8% of the total budget.

But we're very proactive at trying to disarm that, you know, before it becomes a big number. Because nobody – we just never like being in non-op properties, you know, generally. Okay.

Great. Understood. That's it for me. Thank you for the time.

Thank you. Our next question comes in the line. Philip Sonson from Capital One. Your question, please.

Hey, guys. Thank you. I also wanted to ask about the 21 program. I think it was only a month or two ago you guys were talking about running six rigs throughout next year and growing only by 3% to 5% for about $450 million in CapEx. Now it sounds like you're talking about adding a seventh rig in the second quarter, spending closer to $550 million and growing by 6% to 8%. Sounds like the change in tech mainly relates to just the stronger gas prices that you're seeing on the strip, and obviously that helps your leverage ratio if the strip plays out. But, of course, that's only if the strip sort of holds true or if you actually hedge the strip. So I guess my question is – why chase those higher prices that you're seeing with higher activity? Why not just let the higher prices flow straight to the bottom line in terms of additional free cash flow? And if you like the prices and actually want to grow by that amount, why not just hedge the majority of your production for both 21 and 22?

Well, I think it's because I think for 21, I think you're – your suggestion would be a way to optimize it, but we think that's very short-term thinking. And, you know, it would be a way to optimize it, but we think that's very short-term thinking. And, you know, if you're focused on 22, I think people will become more focused on it as we get in the middle of 21. You know, yeah, the underinvestment really, you know, means no growth in production in 22. And so I think that we're really making that additional investment, you know, really for 22. And, you know, we can defer it. So if the prices are weaker, you know, we won't add the seventh rig. We're not committing to it in advance at all. But it is to present you a more balanced program in 21 that's sustainable versus a program in 21 that's absolutely just maxed out to produce short-term results. Because, you know, before you know it, you'll be in 22, and then all of a sudden it will be like, well, you know, you're no longer making any progress toward delevering because you haven't made enough investment.

We thought we would level it out. Again, that's accelerating a little bit of CapEx in the fourth quarter to level out the beginning of 2021 and be really consistent when prices are high. Right now, we have 64% hedge in 2021 and then propel you over into 2022 with a 5% production growth. At the same time, We do think that we balance two things. We balance the growth properly, and yet we deliver quicker at the same time. So it's not that we have to make a big correction sometime in the latter part of 2021 to change what we're doing in 2022 because, you know, if you don't spend a decent amount of money drilling, your production will drop off. Any of these shale companies, whether they're Appalachia or oil, it doesn't matter. you do have to have a decent amount of spending. And where we're located, it tells us that we need to balance this budget today and reset it today. Phillip, and you've been very nice in your writings about what you expect us to do. And, again, we don't want to disappoint anybody. We want to make sure everybody knows why we're laying this out and knowing we can change it. If we need to change it, we can change it. If prices go a little higher, we change it. If they go lower, we change it. But we think this is the right way for the next, you know, two years and two months.

Yeah, the free cash flow is not being sacrificed. I mean, given the prices that we see, you know, we are still going to have very substantial free cash flow. At the same time, have the right investment. So then you look up and say, you know what, 22 looks pretty good too. It's not like this is a one-year wonder. And I think that's the opportunity. But as we answered the question before, we're looking at prices every day, both in the – we're looking at the NYMEX prices and the future strip where you can't hedge, and then also, you know, the cash prices. And, you know, we will be very reactive to that and not, you know, end up, you know, accelerating capital expenditures into a declining price environment. That's something we definitely will not do.

Yeah, I mean, I guess the concern is it was only less than 30 days ago we're shutting in volume because of low spot prices, right? And then we're talking about adding an additional rig next year. So I guess my follow-up would be would you look to hedge more 21 – I'm sorry, 22 volumes before you added that seventh rig?

Oh, definitely. Absolutely. And then, you know, by the time we add it, you know, that their hedge positions need to be more established for 22.

Remember, our hedge positions, we want to be between 50 and 70 percent and maybe 60 to 70 percent.

Of the next 12 months.

Absolutely, Phillip.

We will not be going into it on a hedge basis. So we will continue to deliver on the hedges and the time frame that we continue, you know, that we promise, which is that 12 to, you know, basically 12 months, but 12 to 18 months. So. Yeah, and we have to be able to establish those to support that rig. If not, it won't happen.

Yes, for the leverage we have, I mean, we have to hedge. We should do that. So, yes, that's a commitment to you.

Okay. That makes sense. And then maybe just also if I could just – I guess there's been some – obviously some large corporate mergers announced in the last 90 days or so. Just wanted to get your latest thoughts on this potential consolidation in the Hainesville.

Well, you know, our goal is we hopefully today we reset the program and our execution will be, you know, it will be a happy meeting. I think that if we continue to execute, I think the stock price will perform. I think that you're going to have some stranded Haynesville producers that will need to do something. You know, hopefully what we've done, Phillip, we've said we'll need to do something. You know, hopefully what we've done, Phillip, we've set ourselves in the middle of kind of a square where to go to exit, you've got to at least talk to us or look at us, and we can evaluate if there's an opportunity for us to grow and have a higher market cap and more size, but at the same time continue to delever and to continue to have our high margins. And if we can't do that, then we're not interested in any of those opportunities, I think. You know, we've been smart enough to say yes on the Covey Parks of the World and some others, and we're not going to lose that edge that we have because that edge is everything. But we're not going to lose it, and yet, you know, we're not going to go sit in the corner and not look at opportunities to expand if, in fact, those make the equity owners stronger and the bondholders stronger and our banks stronger. So we'll keep shopping all the time, and we'll keep executing.

Sounds good. Thanks, guys. Appreciate it.

Yes, sir.

Thank you. Our next question is from the line of Kashi Henderson from Simmons Energy. Your question, please.

Good morning, and thank you for taking my questions. So just one or two quick ones for me. So I was wondering if you could give us a refresher on how to think about you know, corporate-based declines. I'm assuming since you pretty much shut down activity over the last few months, you have, you know, improved visibility onto what that corporate decline looks like and then maybe how we should think about that expectation or your corporate decline expectations over the next several years.

Well, what we've messaged in the past is that the corporate decline rate is about 40%, upper 30s to 40%. you know, if we look out over the course of the next year, so around that 40% level, then it'll improve kind of by 5% to 10% in the second year and then continue to flatten out as we have more of the established production base at a lower decline. So that, in terms of the first 12 months, kind of that plus or minus 40% going down to, I guess, 25% to 30%, and then, you know, kind of flattening out there.

Got it. Got it. That was it for me. Thank you.

Thank you. And this does conclude the question and answer session of today's program. I'd like to hand the program back to Jay Allison for any further remarks.

Yes, sir. And again, everybody that stayed the whole hour on the call, I mean, you can't imagine how thankful we are that you spent that hour with us. And again, our goal is to reset the program for the fourth quarter of this year and then in 2021, 2022, to give you something that we think we can really beat. And we want to adjust this capex structure to maximize our advantage to access this to this demand market. that we have in the Gulf Coast. That's a great advantage we have. It's a material geological advantage we have. We just have some great exposure to Henry Hub prices right now. We want to use that. If we need to change this budget, it will be pulled back. But it's real and it's reset and it's good. And, again, we thank you for being a partner with us. And I think the brighter days are ahead of us. You know, our rearview mirror is pretty small, and the windshield is really big, and gas prices look really good. And you've got a really good team here committed. And, you know, we take – if there's a good day or a bad day, we take whatever that day is. And we're accountable to you. So thank you. Thank you. We'll give you our best.

Thank you, ladies and gentlemen, for your participation at today's conference. This does conclude the program. You may now disconnect. Good day.