Earnings Call: Q3 2020

Nov 5, 2020

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 a listen only mode. After the speakers' presentation, there will be a question and answer session. 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 the introduction this morning. And again, I want to thank everybody that's taking 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 really in our corporate life. We're all human and we do understand the Q3 results are somewhat disappointing. Quite frankly, and I can speak for me and for everybody else in the management team, we hate it. And 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. I think our goal this morning is to share what we see for the Q4 2020 as well as 2021 2022 and to show you, our stakeholders, how we plan to delever our balance sheet in those years by using our strength of our peer leading high margins and low cost that we've created in the Haynesville 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 Haynesville coupled with the right size capital program over the next years can delever the balance sheet and expand our trading multiple 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 Q3 results and then we'll get to the Q and A and we'll answer any question that you have and be accountable for it. Welcome to the Comstock Resources Q3 2020 financial and operating results conference call. You can view a slide presentation during or after this call by going to our Web site at www.comstockresources.com and downloading the quarterly result presentation. There you'll find a presentation entitled 3rd Quarter 2020 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns our President and Chief Financial Officer Dan Hairston, our Chief Operating Officer and Ron Mills, our VP of Finance and Investor Relations. Please refer to Slide 2 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 3. On Slide 3, we discuss the highlights of the Q3. November is the 1st 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 process we're receiving for our production. The reduced activity we had in the first half of the year combined with the 3rd 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 Q3. We added 2 additional operated drilling rigs to bring our working rigs back up to 6, which is where we were at the beginning of the year and currently have 3 frac 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 26,000,000 cubic feet per day. We did have a rocky quarter, as I mentioned on the production front, which partially was self inflicted as the ramp up of activity drove our shut in percentage up to 7% in the quarter. The higher spending in the quarter reflects restarting a program we put on hold in the Q2, 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 costs 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 weak 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, we recently decided to increase our completion activity planned in the Q4 by running an additional frac crew, which moves up the completion of 7 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 In the Q3, we completed a follow on $300,000,000 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 $928,000,000 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 $212,000,000 Our adjusted EBITDAX came in at $148,000,000 and our operating cash flow was $93,000,000 or $0.38 per share. We reported an adjusted net loss of $13,800,000 or $0.06 a share. With higher production and stronger natural gas prices, we anticipate returning to profitability in the Q4, which is now. I will have Roland go over the financial results in more detail. Roland? All right. Thanks, Jay. On Slide 4, we summarize our financial results for the Q3 of this year. Our production for the Q3 totaled 103 Bcf of natural gas and 354,000 barrels of oil. Total production of 105 Bcfe was 4% higher than the Q3 of 2019. Our oil and gas sales, including the realized hedging gains, were $212,000,000 which was 15% lower than 2019. 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%, which offset the production growth that we had in the quarter. Adjusted EBITDAX came in at $148,000,000 which was about 22% lower than the Q3 of 2019 and operating cash flow of $93,000,000 was about 35% lower. We did report a net loss of $130,900,000 for the 3rd quarter or $0.57 per share, but most of that loss is attributable to the 100 and $55,600,000 unrealized loss on the mark to market of our hedge positions. And that is all caused by the substantial improvement to futures 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 $13,800,000 or $0.06 per diluted share for the quarter. On Slide 5, we summarize our financial results for the 1st 9 months of this year. Production for the 1st 9 months totaled 349 Bcfe, including about 1,200,000 barrels of oil, which is 90% higher than our production for the first the same period in 2019. Of course, most of this increase is due to the acquisition of Covey Park Energy, which completed in July of 2019. Oil and gas sales, including realized hedge gains, were $716,000,000 40% 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% lower than the prices we had for natural gas in the same period in 2019. Our adjusted EBITDAX came in at $511,000,000 which was 35% higher than 2019. Operating cash flow was $367,000,000 and that's 31% higher than 2019. We did report a net loss of $160,900,000 for the 1st 9 months of this year or $0.77 per share. Again, this was due to the mark to market loss, the unrealized mark to market loss on our hedge book. Adjusted net income, excluding the unrealized hedging losses and other unusual items, was $12,900,000 or a net income of $0.06 per diluted share. The 3rd quarter production was adversely impacted by a higher shut in level than normal as you can see on Slide 6. 7% of our natural gas production was shut in, in the 3rd quarter as compared to 4% in the 2nd quarter. Much of that shut in is due to offset frac activity either by our simultaneous operations or other Haynesville 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 12 to 14 days or so of October, we did experience wide differentials in the daily cash market at Perryville and then other index is 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've been 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 not part of our baseload sales. So we chose to restrict some of the new wells that were coming on in September. And then given that's 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 $0.10 in the Q3. This situation did continue into October, really only the 1st couple of weeks of October. And then we took an action in the very first part of October to actually curtail for price reasons 300,000,000 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 fill it up. And then we saw that the about mid October, we saw the daily cash prices go back into normal relationship and differentials narrow. And then we put all that gas really back into the market. So I think as October has finished out and as we entered November, we've seen a very healthy situation, which has been supported by very favorable kind of injections to storage and even today a withdrawal. We also saw that obviously our non operated oil production, which is primarily located in the Bakken region, also has continued to experience substantial curtailments, which carried through in the Q3. 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 Bakken region. On Slide 7, we cover our hedging program. For the 1st 9 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 $133,000,000 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 $10,000,000 a day of natural gas for the Q4 since we last reported earnings and we added about $38,000,000 a day of natural gas collars in 2021 and about $12,000,000 a day of collars in 2022, which gives us a good protection level, but also gives us exposure to the higher prices. So as you look ahead for the Q4 of 2020, we have 663,000,000 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 836,000,000 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 8, we detail our operating cost per Mcfe produced. And overall, these were pretty comparable to the Q2. So our operating cost averaged $0.55 in the 3rd quarter as compared to our 2nd quarter rate of $0.54 Gathering costs were $0.21 production at Valorem Texas 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 cost 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 this makes us more comparable to our peers. On Slide 9, we detail our corporate overhead per Mcfe and our cash G and A costs were $0.07 in the 3rd quarter, which is slightly up in the 2nd 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 and A averaged $0.95 in the 3rd quarter, which was about $0.08 higher than the 2nd 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 use to do amortization with. On Slide 11, we recap our Q3 and our the 1st 9 months of 2020 capital expenditure program. So we spent $110,000,000 on development activities in the 3rd quarter and $94,000,000 of that was related to our operated Haynesville Shale properties. For all of 2020 so far, we spent $316,000,000 including $259,000,000 on the operated Haynesville properties. We've drilled 36 or 28.6 net operated horizontal Haynesville wells so far this year and we also completed 9.6 net wells that we drilled in 2019. We've spent $56,000,000 on non operated activity and for other activity so far this year. We generated $367,000,000 in cash flow for the 1st 9 months of this year, resulting in free cash flow $30,000,000 after we paid the dividends on the preferred shares. After dropping our operated rig count to 4 rigs in April, which was down from 6 back in January, we've increased our operated rig count back to 6 rigs. And in the 4th quarter, we expect to spend about $150,000,000 to $170,000,000 this year to drill 17 or 16.4 net operated Haynesville Wells and then to turn to sales 22 or 17.6 net Haynesville wells. We made the decision recently to keep a third frac crew busy in the Q4, which we originally planned to release and then bring back in early 2020. This does add about $30,000,000 to our 2020 spending, but and the reason for it was to accelerate the completion of 7 wells that before we plan to complete in 2021. And this is in order to take advantage of the higher gas prices, especially that we see for the Q1 of 2021. And it was just a it was a decision based on if we kept our original schedule, we compare that to keeping this 3rd rig, which was performing well for us and operations asked us to look at that and we said, we actually make $15,000,000 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 Q4 with that, we now expect to spend about $450,000,000 to $500,000,000 this year, which would have drilled 53 or 45 net operating Haynesville wells and turned 55 or 42.2 net operated Haynesville wells to sales. We also participated we also plan to participate in 18 or 1.3 net non operated Haynesville 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 DUCs are drilled in 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 $525,000,000 to 575,000,000 and drill 70 or 56.5 net operated Haynesville wells and turned 65 of those wells or 56.6 net wells to sales in the year. Our initial plans right now are to add a 7th operated rig and we would do that in the Q2 of next year. Obviously, as we get to that point, we'll assess 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 what when we spend the CapEx 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 with the plans we have and we target to have a minimum of at least $200,000,000 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 3rd quarter. And during the Q3, as Jay mentioned, we issued $300,000,000 of new unsecured notes to term out a portion of the borrowings outstanding under our credit facility. So we ended the quarter with about $500,000,000 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. With a quarter ending cash position of $28,000,000 our current liquidity now stands at $928,000,000 We have just over $2,250,000,000 of senior notes outstanding and that's comprised of $619,000,000 of our 7.5 percent senior notes due in 2025 $1,650,000,000 of our 9.75 percent senior notes due in 2026. So I'll now turn it over to Dan to cover the Q3 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 1943 net future drilling locations identified on the acreage with 96% 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 D and C count up to 252 wells since early 2015. Like Roland mentioned, we have added 2 additional rigs since our last call and we're now running a total of 6 rigs. Due to the break in the frac activity in Q2, we started out the Q3 with a total of 21 DUCs. Since worked that down to 16 wells currently. Our go forward DUC count should remain roughly at this level through year end and into next year. We started out the quarter with 2 frac crews. We ramped up to 3 frac crews in early September when we will continue to run these 3 frac crews through the end of the year. Based on our current 6 rig schedule to 7 rigs next year, we anticipate running on average 2.4 frac crews in 2021. Over on slide 14, this is our latest HaynesvilleBossier itemized drilling inventory at the end of the 3rd quarter. Our gross operated inventory currently stands at 2,401 locations with our net operated inventory at 1763 locations. This represents a 73% average working interest on our operated inventory. Our non operated inventory is at 13 52 gross locations with a net non operated inventory at 180 wells and this represents a 13% average working interest. For the gross operated inventory, we have 4 94 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 Haynesville 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 Haynesville laterals has increased to 420, up from 389 at the end of the Q2. 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 Walspom, our Logansport and Elm Grove acreage. The wells were tested at rates of 16,000,000 a day to 35,000,000 a day with a $26,000,000 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 per foot. As mentioned earlier, we have 3 frac crews working today and we'll maintain that level of completion activity through the end of the year. The current DUC count as before stands at 16 and that should maintain through the end of this year and into next year also. On slide 16 is a chart. This illustrates the progress we continue to make driving down our D and C costs. These results track only our medium to long term laterals, which have the lateral lengths of greater than 7,000 feet. Our D and C costs continue to trend down in the Q3 and is starting to flatten. We again achieved our lowest all in D and C cost to date at $9.98 a foot. Contributing to this low D and C cost were 2 record low cost wells that averaged less than $900 a foot. This D and C 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 costs 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 frac intensity to evaluate performance. We have observed a slight reduction in our EURs, which we expected to a small degree and which made sense with the low gas price environment we're in earlier in the year. Starting in September, we have shifted back up to our original job size in the 3500 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 the 1000 to 10.50 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 will go over this slide and then turn it over to Ron for some guidance. So I would 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. For the first half of this year, we've remained primarily focused on free cash flow 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 2021, driven by expectations for significant declines in natural gas supply due to a continued reduction in natural gas directed drilling and completion activity and less associated gas production from related activity in oil basins resulting from the collapse of oil prices. Starting in the 3rd quarter, we went back to work and resumed completion operations with 3 frac crews in order to work through the backlog of DUCs that Dan had talked at. And we've added 2 additional drilling rigs to generate production growth late this year and more importantly in 2021 to coincide with improved natural gas prices. We also recently made the decision to accelerate well completions originally planned in 2021. We're keeping a 3rd frac crew working in the 4th quarter, which moves about $30,000,000 to our 2020 budget from 2021 in order to complete 7 wells 3 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. With all our focus on reducing activity and delaying start up for the new wells, we expect to have about a 2% pro form a 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. We paid almost half of our production over the remainder of 2020 and 64% of our 2021 production and have strong financial liquidity of $928,000,000 following our recent bond offering. So with that, now I will 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 Q4 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 Q4, we anticipate spending $150,000,000 to $170,000,000 on our drilling and completion activities, which will result in 2020 total spending being $450,000,000 to $500,000,000 That's higher than we discussed in the Q2 call due to laterals getting longer, some additional workover activity, some non operated activity and some minor leasing costs. Q4 'twenty 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 Bcf to 1.3 Bcf a day despite the impacts of the shut ins and the hurricane impacts previously discussed. Looking ahead to next year, we're providing initial CapEx guidance of $525,000,000 to $575,000,000 and production guidance of 1.325 to 1.425 Bcf a day, which anticipates the addition of the 7th 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 point 2 $7 The production and average warrant taxes are expected to average 0 point expected to be in the $0.05 range $0.05 to $0.07 range on a unit basis. For the rest of the call, we'll just we'll turn it over for questions and answers. Our first question comes from the line of Derrick 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 7th rig 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. Derek, 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 4 to 6 months later because we always drill on pads just because it increases the drilling efficiency so much. So you have 2 to 3 wells kind of waiting before they come online. So and given that we're looking at so I think as we look ahead and into 2022, we wanted to create some guidance that even though it didn't add a lot of production to '21 and probably the action we did to actually to spend additional dollars in the Q4 probably has a great impact on 'twenty one. But adding an extra rig, it 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 2021 and then going back to hardly any growth in 2022. So I think given the outlook for gas and 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 get leverage below 2 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 are sensitive to the fact that the market doesn't like 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're we think it's the best action for the company as to 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 getting the maximum results next year. Well, again, our goal is to 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 Q4 2020 and we said we should keep a frac crew busy. We should lean into 2021 because again, if you look at the advantage we have, I mean, we have advantaged access to the demand market of the Gulf Coast. We're favorably exposed to Henry Hub. 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. So 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 cost and high margins. We've got to give you an outlook for the Q4 as well as 'twenty one, 'twenty two. 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, Jainrel. And that certainly makes sense. And as my follow-up, referencing Slide 6, 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? That's a good question. I mean, a large impact is always the simultaneous operations, which is happens now because we do you have to protect your offset production from offset frac activity either we created or one of our neighbors creates it. So, yes, I think it's probably realistically a 5% number, pretty flat. I mean, especially as we keep a more consistent program, I think it stays more consistent and doesn't have the kind of gyrations. And the unknown is just their power issues or pipeline issues that are caused by other events. And then I think what for the first time ever, really in this late September, October period, as a major producer in the Haynesville 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. It's the same thing that the large producers did in Appalachia and it's our responsibility to do that. And our actions allow that market to recover pretty quickly. And it also allowed us to realize, instead of realizing a very low price for the gas to save it and then produce it a week later at a higher price. So I think we're also going to have to be mindful of that and controlling the flow of gas, especially the swing gas that's open into a market. Every year so far, there has been a sensitive period for gas as it exits the injection period and storage fills up in this October is just 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 we it seems like we've made a good adjustment through it and operators like us responded and very proactive to keeping that situation workable. I think you won't see the impact of the private equity backed Haynesville players, but they will 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 look at our drilling program, kind of have a pool of information from the offset operators. 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 Dan will tell you that it's probably 5%, but I want to say 5%, and that's kind of where we are right now even with our footprint. 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 we do have initiatives going on in 'twenty one that we're going to be able to really get less and less gas sold at Curryville, which is that's more vulnerable to especially for gas coming out of basin like it did in disrupting that basis. So we've always had a goal of removing ourselves from that market. And I think next year, there's several initiatives. The big one obviously is the Acadian line opening up, but we also have we've also been working with our midstream partners to give us some other ways to bypass Perryville and get and move gas more to the Gulf, or at least have the flexibility to respond to that. That. Our next question comes from the line of Don MacIntosh from Johnson Rice. Your question please. Good morning, Jay. Thanks for the Good morning. Provided so far. I had a question, I understand the pickup in activity and that attacking leverage can be a little easier from the EBITDA side sometimes. So how under this new program, where do you see leverage over 2021 2022 and targeting that we've talked about 2.5 times I think in the next year, but getting down under that 2 times, does this get you there faster or what you're seeing in the past? Yes, it does. Raul, I'll give you some numbers, I think, but we will deliver faster. And it's all because of the market demand and the process we get at Henry Hub. Now we do deliver. When we had all of our 1 on 1 conference calls, we said the only reason we would add a rig or complete wells earlier is if it allowed us to delever 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 2x as we finish up 2022 with this plan. And I think by investing a little bit into 2021, it actually allows us to hit that goal there versus just being shy of it if we let 2022 just have kind of a under have a more of a flat production profile. Again, we're it's been erratic for the company obviously to go from growing at a 34% rate back in 2019 to 2% this year is probably what it's going to end up being with all the and then back to more sustainable levels the 6% to 8%. But we're really targeting to try to get to more of a 5% growth. That's 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 the strip today gives us that opportunity to achieve all that with this program in this 2 year period. And then that gives us a growth in 2022, maybe 5%. So what our goal today, again, it's to reset the program for the Q4 2020 and for 2021, 2022. That's exactly our goal. So that was a great question. It is all about delevering with where we are in the locations we have and the profits that we make. All right. Thank you. And then for my follow-up, on the you mentioned in the call maybe moving to a little bigger profit. What are kind of the 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? Yes. This is Dan. So yes, 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. 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 for and this is really for the wells maybe that are over in that Stateline area, the Greenwood, Waskom area. And so when you run it at the higher gas prices, I mean, it's clearly you need to pump the bigger jobs, which also means you're pumping more water. It's just a matter of the economics. I mean, the wells deliver a better PV-ten value when you do that at the higher gas prices. Yes. I think it's a good question too because we intentionally we set the bookings. We look at companies that use £5,000, £6, £7,000 of profit. We didn't think that would be what we need to do. We dropped down to the lower bookends of this 24, £5, £600, £600, 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 upfront. But when you have a gas price of 2.9 $3,000 $3.10 $3.20 $3.20 and you look at the PV value and you look at how quick these wells pay out and the increased volume, then it's easier to say the right thing to do is to spend a little bit more money. We're still in that $1,000 to $1,050 per completed foot to have a much better performance, which drives our leverage. And so 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 from the line of Umer Choudhary 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 and 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, we're going to maintain it. And so I think that is definitely a big factor. And I think we've gotten overall as the market seems to be fairly comfortable that at least in 2021 the stage is set for this $3 kind of area gas price. And we'll certainly reassess adding a rig by midyear next year if it's not at that level anymore. So we're not at all locked into one strategy, but we wanted to present more of a balanced program that didn't just focus on 2021 and absolutely maximize 2021, which the 6 rig program really can do. But that comes at the expense of 2022 and you stop making the progress towards your leverage goals in 2022 if you don't make any investment for it. So that was the goal of today. And again, the beauty is we don't have any farm transportation obligations at call just to drill. We don't have any minimum volume commitments at call just to drill. 96% of our acreage is held by production. So our CapEx budget is just driven internally by what we need to do to improve our balance sheet and pay down our debt. We'll be very reactive to the changing environment. So as we were this year playing defense in the first half of this year, we could be very reactive because we don't have long term obligations that drive us to have to drill any wells at all. 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, we usually people worry about the quality of your locations. Nobody ever asked us about that. So we've taken that off the table. They just say, how can you delever? I mean, how can you delever? And where we are, we're the only pure or Haynesville sized company of this size. We say, well, again, our advantage is this access to the Gulf Coast. And we do have direct 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 basin. And that's why we've got to tell you we're going to reset the whole program for Q4 of this year in 'twenty one, 'twenty two. We also tell you that whatever we need to do to we need to shut in swing gas because the prices are low. You've now seen that we've done that. We demonstrated 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 as a partner as we create even a greater company. Thank you for the color. That's really helpful. Thank you. Yes, sir. Thank you for the time and the question. Thank you. Our next question comes from the line of Kevin Gunning from Citi. Your question please. Hey, good morning. Just a quick one on 2021 expectations. 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 are you seeing any of those private equity backed companies kind of gearing up for higher production growth next year as well? Yes, we don't see we have very limited touch points with other companies. So the non op part of our portfolio has always been fairly small. And basically, we really like to do acreage trades to try to even make it smaller. And I think that we actually finished some really good acreage trades that you saw kind of come through the location numbers and acreage numbers this quarter with Geo Southern and Indigo that really improved our overall lateral lengths overall and reduced our non op potential activity in the future and also actually gave us more locations in our very, very best lowest transportation cost area. So I mean it was really a big win and I'm sure that we also met their goals and things they were trying to accomplish. And so, yes, 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, 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, we'll sell down the wellbore to people that are interested in investing in that. So I think we probably always have budgeted. I mean, Ron, you might say that we have potentially $35,000,000 to $40,000,000 of non op activity that we kind of always expect to have. That's about right. It is typically average kind of in that 6% to 8% of the total budget. So we're very proactive at trying to disarm that before it becomes a big number. Because nobody we just never like being in non properties generally. Great. Understood. That's it for me. Thank you for the time. Thank you. Our next question comes from the line of Philip Johnson from Capital One. Your question please. Hey guys, thank you. I also wanted to ask about the 2021 program. I think it was only a month or 2 ago, you guys were talking about running 6 rigs throughout next year and growing only by 3% to 5% for about $450,000,000 in CapEx. Now it sounds like you're talking about adding a 7th rig in the 2nd quarter, spending closer to $550,000,000 and growing by 6% to 8%. It sounds like the change in TAC 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 2021 2022? Well, I think it's because I think you got I think for 2021, I think your suggestion would be a way to optimize it. But we think that's very short term thinking. And if you're focused on 2022, I think the market people will become more focused on it as we get in the middle of 2021. Yes, the under investment really means no growth in production in 2022. And so I think that we're really making that additional investment really for 2022. And we can defer it if the prices are weaker, we won't add the 7th rig. Rig. We're not committing to it in advance at all, but it is to present you a more balanced program in 2021 that's sustainable versus a program in 2021 that's absolutely just maxed out to produce short term results because before you know it, you'll be in 2022 and then all of a sudden, they'll be like, well, these are 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 Q4 to level out the beginning of 2021. It would be really consistent when prices are high right now. We have 64% hedged in 2021 and then propel you over into 2022 with a 5% production growth. And at the same time, we do think that we balance 2 things. We balance the growth properly and yet we delivered 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 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, 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, Philip, 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. We need to change it, we can change it. Process 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 2 years 2 months. Yes. And I bet the free cash flow is not being sacrificed. I mean, given these high prices that we see, 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, 'twenty two looks pretty good too. It's not like this is a 1 year wonder. And I think that's the opportunity. But like we as we answered the question before, we're looking at prices every day both at the we're looking at the NYMEX prices and the future strip where you can hedge and then also the cash prices and we will be very reactive to that and not end up accelerating capital expenditures into a declining price environment. That's something we definitely will not do. Yes. 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 additional rig next year. So I guess my follow-up would be, would you look to hedge more '21 I'm sorry, 'twenty two volumes before you added that 7th rig? Oh, definitely. Absolutely. And that's by the time we added, that their hedge positions need to be more established for 2022. Our hedge positions, we want to be between 50% 70% and maybe 60% to 70%. Over the next 12 months. Absolutely, Philip. We're certainly not going to we'll not be going into on a hedge basis. So we'll continue to deliver on the hedges and the timeframe that we continue that we promise which is at 12 to basically 12 months, but 12 to 18 months. So yes, and if we can we have to be able to establish those to support that rig. If not, it won't happen. Yes. So 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 potential consolidation in the Haynesville. Well, our goal is we hopefully today, we've reset the program, and our execution will be happy meetings. 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. Hopefully, what we've done, Philip, 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 higher market cap and more size, but at the same time continue to delever and to continue to have our higher margins. And if we can't do that, then we're not interested in any of those opportunities. I think 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 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 bank stronger. So we're going to 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 comes from the line of Kashy Anderson from Simmons Energy. So just one or two quick ones for me. I was wondering if you could give us a refresher on how to think about corporate based declines. I'm assuming since you pretty much shut down activity over the last few months, you have improved visibility on to what that corporate decline looks like. And then maybe how we should think about that expectation 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%. If we look out over the course of the next year, it's around that 40% level and then it will improve kind of by 5% to 10% in the 2nd 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 1st 12 months, kind of that plus or minus 40% going down to, I guess, 25% to 30% and then 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, sure. And again, everybody that stayed the whole hour on the call, I mean, we're you can't imagine how painful we are that you spent that hour with us. And again, our goal is to reset the program for the Q4 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 advantaged access 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 process 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. 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 we take if there's a good day or bad day, we take whatever the 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 in today's