Earnings Call Transcript - CRK Q3 2020

Operator, Operator

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 speakers' presentation, there will be a question-and-answer session. I would now like to introduce your host for today's program, Mr. Jay Allison, Chairman and Chief Executive Officer. Please go ahead, sir.

Jay Allison, CEO

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 many of you, and you're really good friends who have been with us for a long time. Today is an important day in our corporate life. We're all human, and we do understand that the third quarter results were somewhat disappointing, quite frankly. I can speak for myself and for everybody else on the management team; we hate it. They are disappointing for the reasons that you're aware of, and they're all logical reasons. They're still disappointing; shut-ins and curtailments related to Hurricane Laura, non-op curtailments, and there's a list of other small reasons. 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 delever our balance sheet in those years by using our strength of our peer-leading high margins and low costs created in the Haynesville during a period where the outlook for natural gas is extremely bullish, the most bullish it has been in over 10 years. Our job in the next 45 minutes is to avoid any disappointments in the future, and show you how our margins in the Haynesville, coupled with the right-sized capital program over the next years, can delever the balance sheet and expand our trading multiples so that we all are winners, all based on the gas price outlook that we see today. Thank you for trusting us. If we've dented that trust at all, 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. I will start with our third quarter results, and then we'll get to the Q&A to answer any questions you have and be accountable for them. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results 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, 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 and 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. The November natural gas prices 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 a decline in associated gas resulting from low oil prices, have caused the 2021 future natural gas prices to improve substantially. Since January of 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 low prices we were receiving for our production. However, 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. 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 planned to be ending the year. Currently, we have three 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 million cubic feet per day. We did have a rocky quarter, as I mentioned, on the production front, which was partially 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 second quarter, but it was the right move as we look forward to improved gas prices. We achieved 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 slightly 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, we now see that with gas prices closer to $3+, it makes sense to invest a little more for profits. As we will discuss more today, we recently decided to increase our completion activity planned in the fourth quarter by running an additional frac crew, which moves up the completion of seven wells that we plan to complete in 2021. The additional investment will pay off in 2021, allowing us to have higher production to take advantage of 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 successfully reduced our outstanding bank borrowings from 57% of availability to just 36% of our availability. By freeing up our 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 wells, including hedges, totaled $212 million. Our adjusted EBITDAX came in at $148 million, and our operating cash flow was $93 million or $0.38 per share. We reported an adjusted net loss of $13.8 million or $0.06 a share. With higher production and stronger natural gas prices, we anticipate returning to profitability in the fourth quarter.

Roland Burns, CFO

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 realized hedging gains, were $212 million, which was 15% lower than 2019, driven by lower oil and gas prices in the quarter. Oil prices in the quarter averaged $33.52 per barrel, with the hedging gains we had, 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 million, which was about 22% lower than the third quarter of 2019, and operating cash flow of $93 million was about 35% lower. We reported a net loss of $130.9 million for the third quarter or $0.57 per share. However, most of that loss is attributable to the $155.6 million unrealized loss on the mark-to-market of our hedge positions, caused by the substantial improvement in future natural gas prices since the end of the second quarter. Our adjusted net income, excluding this unrealized mark-to-market hedging loss and other unusual items, was a loss of $13.8 million or $0.06 per diluted share for the quarter. On 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. Most of this increase is due to the acquisition of Covey Park Energy, which we completed in July 2019. Oil and gas sales, including realized hedge gains, were $716 million, 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 million, which was 35% higher than 2019. Operating cash flow was $367 million, and that is 31% higher than 2019. We did report a net loss of $160.9 million for the first nine months of this year or $0.77 per share, again due to the unrealized mark-to-market loss on our hedge book. Adjusted net income, excluding the unrealized hedging losses and other unusual items was $12.9 million, or a net income of $0.06 per diluted share. The 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 compared to 4% in the second quarter. Much of that shut-in was due to offset frac activity either by our simultaneous operations or other Haynesville operators. We also temporarily shut in a portion of our production for about a week due to the impact of Hurricane Laura, which caused widespread power outages in our region. In September, we experienced wide differentials in the daily cash market at Perryville and other indexes in our Southern Gulf region. This was due to concerns in the natural gas market over high storage levels, as we've been exiting the period of storage injections. The only gas affected by these daily prices is what we call our swing natural gas that was not sold during mid-week and is not part of our baseload sales. So, we chose to restrict some of the new wells coming online in September. Given the very low price that this swing gas was receiving and the high differentials that month, the declining overall index prices in that volatile month did cause our overall differential in the quarter to widen by $0.10. This situation continued into early October. We took action in the first part of October to curtail, for price reasons, 300 million a day of our production, which we did for about 11 days. This action, combined with the restart of our LNG facilities, helped reduce concerns about storage filling up. We saw, by mid-October, daily cash prices return to a more normal relationship, and the differentials narrowed. Then we put all that gas back into the market. Our non-operated oil production, primarily located in the Bakken region, also continued to experience substantial curtailments during the third quarter, with about 12% of our oil production shut-in by operators due to very low oil prices. 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 received. Overall, during that period, we had realized hedge gains of $133 million. With the improvement in future natural gas prices, we also took that opportunity to continue to add to our hedge book at higher levels than previously, using collars. We've added about 10 million a day of natural gas for the fourth quarter since our last report, along with about 38 million a day of natural gas collars in 2021, and about 12 million a day of collars in 2022. This gives us protection but also exposure to the higher prices. For the fourth quarter of 2020, we have 663 million cubic feet of our gas and about 2,800 barrels of oil hedged. The weighted average floor price for 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. We are on target to have 60% to 70% of our 2021 production hedged, and we'll work to hedge our 2022 volumes appropriately. On slide eight, we detail our operating costs per Mcfe produced. Overall, these were pretty comparable to the second quarter. Our operating cost averaged $0.55 in the third quarter compared to our second-quarter rate of $0.54. Gathering costs were $0.21, production and ad valorem taxes averaged $0.09, and field-level costs were $0.25. We did reclassify our ad valorem taxes that used to be shown as part of just lifting costs and now include those in production taxes to improve comparability to us and other producers. On slide nine, we detail our corporate overhead per Mcfe and our cash G&A cost was $0.07 in the third quarter, slightly up from the second quarter, mainly due to the lower production level. Slide 10 details the depreciation, depletion, and amortization per Mcfe produced. Our DD&A averaged $0.95 in the third quarter, about $0.08 higher than the second quarter, mainly due to much lower backward-looking SEC-type prices used for amortization. On slide 11, we recap our third quarter and the first nine months of the 2020 capital expenditure program. We spent $110 million on development activities in the third quarter, with $94 million related to our operated Haynesville Shale properties. For all of 2020 so far, we spent $316 million, including $259 million on the operated Haynesville properties. We've drilled 36 or 28.6 net operated horizontal Haynesville wells this year and completed 9.6 net wells drilled in 2019. We've spent $56 million on non-operated activity for other activities this year. We generated $367 million in cash flow for the first nine months of this year, resulting in a free cash flow of $30 million after dividends on preferred shares. After reducing our operated rig count to four rigs in April, down from six rigs in January, we've increased our operating rig count back to six rigs. In the fourth quarter, we expect to spend about $150 million to $170 million this year to drill 17 or 16.4 net operated Haynesville wells and turn to sales 22 or 17.6 net Haynesville wells. We recently decided to keep a third frac crew busy in the fourth quarter, originally planned to release and then bring back in early 2020. This adds about $30 million to our 2020 spending. The reason for this is to accelerate the completion of seven wells we originally planned to complete in 2021, allowing us to take advantage of the higher gas prices we expect, especially for the first quarter of 2021. By comparing our original schedule with keeping this third rig working, we've found that we can generate $15 million more by accelerating the completion to take advantage of high gas prices. For the full year 2020, we now expect to spend about $450 million to $500 million, which would result in 53 or 45 net operating Haynesville wells drilled and 55 or 42.2 net operated Haynesville wells turned over to sales. We also plan to participate in 18 or 1.3 net non-operated Haynesville wells and 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 or drilled and uncompleted wells. Looking ahead to 2021, we expect to increase spending slightly over the 2020 level in response to higher natural gas prices. We expect to spend between $525 million to $575 million, drill 70 or 56.5 net operated Haynesville wells, and turn 65 of those wells or 56.6 net wells to sales in the year. Our initial plans are to add a seventh operated rig in the second quarter of next year. As we approach that point, we'll assess the natural gas market in our region and decide if that's still a sound course of action. We do not have long-term commitments for drilling or completion services, so it's clearly an economic decision on when we spend CapEx, and we can react as we did this year, adjusting our spending levels as appropriate. We remain focused on generating significant free cash flow, and we see next year producing a bounty of that with the plans we have. We target 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. During the third quarter, as Jay mentioned, we issued $300 million of new unsecured notes to term out a portion of the borrowings from our credit facility. We ended the quarter with about $500 million drawn on our credit facility and expect to continue to pay that down with free cash flow generated during the rest of 2020 and into 2021. Our quarter-ending cash position was $28 million, and our liquidity now stands at $928 million. We have a little over $2.25 billion of senior notes outstanding, which includes $619 million of our 7.5% senior notes due in 2025 and $1.65 billion of 9.75% senior notes due in 2026. I will now turn it over to Dan to cover the third quarter drilling results in more detail.

Dan Harrison, COO

Okay. Thanks, Roland. On slide 13, this is just our updated outline of our current acreage position, which has increased this quarter to 309,000 net acres. We control the majority of the acreage with a 91% operated position and an average working interest in the acreage of 81%. We currently have 1,943 net future drilling locations identified on the acreage, with 96% of the acreage currently held by production. Since resuming our completion program at the end of June, we have turned 15 additional wells to sales, bringing our total D&C count up to 252 wells since early 2015. As Roland mentioned, we have added two additional rigs since our last call, and we're now running a total of six rigs. Due to a break in the frac activity in Q2, we started out the third quarter with a total of 21 DUCs, which we've worked 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 the quarter with two frac crews and ramped up to three frac crews in early September, and we will continue to run these three frac crews through the end of the year. Moving on to slide 14, our latest Haynesville/Bossier itemized drilling inventory at the end of the third quarter shows our gross operated inventory standing at 2,401 locations with our net operated inventory at 1,763 locations, representing a 73% average working interest. Our non-operated inventory is at 1,352 gross locations, with a net non-operated inventory at 180 wells, representing a 13% average working interest. Of our gross operated inventory, we have 494 short laterals, 905 medium laterals, and 1,002 long laterals. Breaking this down by zone, 54% of our locations are in the Haynesville and 46% 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 second quarter. This inventory provides the company with over 30 years of drilling locations based on our current activity levels. Slide 15 illustrates the progress we are making in driving down our D&C costs, specifically for medium to longer-term laterals over 7,000 feet. Our D&C costs continued to trend down in the third quarter, achieving our lowest all-in D&C costs to date at $998 a foot. Contributing to these low D&C costs were two record-low cost wells that averaged less than $900 a foot. This D&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 remains the same: our current service costs, coupled with our high completion efficiency and smaller jobs, have driven the low costs. Since the last call, we've generated enough production history on the earliest wells completed with the reduced frac intensity to evaluate performance. We've observed a slight reduction in our EURs, which we expected to some degree, especially in the lower gas price environment earlier this year. Starting in September, we shifted back to our original job size in the 3,500- to 3,600-pound-per-foot range as we entered a much better gas market. Based on our most recent well costs, we still aim to keep our costs relatively flat in the $1,000 to $1,050 range, but we acknowledge that the industry may face some upward pricing pressure in 2021. That recaps the operations. I'm now going to turn it back over to Jay for some final comments.

Jay Allison, CEO

Thank you, Dan and also, Roland, thank you. If everybody would go to Slide 17, I'll go over this slide and turn it over to Ron for some guidance. Directing you to Slide 17, we summarize our outlook for the rest of this year and our initial thoughts on next year. For the first half, we've remained primarily focused on free cash flow generation and managing the company through the low oil and natural gas price environment. While natural gas prices remained relatively low through October due to elevated gas storage levels, the outlook for natural gas has improved substantially for late 2020 and 2021 driven by expectations of significant declines in natural gas supply due to continued reductions in directed drilling and completion activity, and less associated gas production from activity in oil basins resulting from the collapse of oil prices. Starting in the third quarter, we resumed completion operations with three frac crews to address the backlog of DUCs Dan referenced. 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. We made decisions to accelerate some well completions originally planned for 2021, keeping a third frac crew in the fourth quarter, moving about $30 million into our 2020 budget from 2021 to complete seven wells three months earlier. The rationale is that we can produce the gas related to these wells earlier in 2021 during the higher gas price months. The strength we lean on this year is our industry-leading low-cost structure and well economics. By focusing on reducing activity and delaying the startup of new wells, we expect to achieve approximately a 2% pro forma production growth this year. Next year, we foresee balanced growth of around 6% to 8% while generating substantial free cash flow to use for debt reduction and to improve our financial leverage. We have hedged nearly half of our production over the remainder of 2020 and 64% of our 2021 production, with strong financial liquidity of $928 million following our recent bond offering. So now I will turn it over to Ron to provide specific guidance for the rest of the year.

Ron Mills, VP of Finance and Investor Relations

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 completion schedule as well as the shut-ins discussed earlier in this call. For the fourth quarter, we anticipate spending $150 million to $170 million on our drilling and completion activities, resulting in total 2020 spending of $450 million to $500 million. That's higher than we discussed in the second quarter call, due to longer laterals, additional workover activity, non-operated activity, and some minor leasing costs. Fourth quarter 2020 production is expected to average 1.15 Bcfe to 1.25 Bcfe per day. Our 2020 production is expected to average at the low end of our prior guidance of 1.25 Bcf to 1.30 Bcf a day, despite the impact of shut-ins and hurricane impacts. Looking ahead, we provide initial CapEx guidance of $525 million to $575 million and production guidance of 1.325 Bcf to 1.425 Bcf a day, anticipating the addition of the seventh rig by mid-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. 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 $1.00, and the cash G&A is expected to be in the $0.05 to $0.07 range on a unit basis.

Operator, Operator

Certainly. Our first question comes from the line of Derrick Whitfield from Stifel. Your question, please.

Derrick Whitfield, Analyst

Thanks and good morning, all.

Jay Allison, CEO

Good morning.

Derrick Whitfield, Analyst

All right. Regarding the 2021 outlook, would it be fair to assume you'll see minimal production from the seventh rig you're adding in 2021 and the real impact will be felt in 2022, where that activity increase could sustain growth in that 6% to 8% range?

Roland Burns, CFO

Yes, this is Roland, Derrick. That's a good observation. Looking at the way that shale companies operate, the capital that we spend today doesn't generate production until four to six months later because we always drill on pads to increase drilling efficiency. Looking ahead into 2022, we wanted guidance that even though it doesn't add much production to 2021, the action we took to spend additional dollars in the fourth quarter likely has a greater impact on 2021. Adding an extra rig doesn't contribute much production in time to affect the numbers. However, it sets the stage for a more sustainable program in 2022 versus having a higher growth rate in 2021 that would diminish in 2022, seeing no growth. Given the natural gas outlook improving, our focus has been on remaining defensive but positioning for better performance next year.

Jay Allison, CEO

Our goal is to determine how we should allocate our capital dollars quarterly. That's why we've analyzed 2021 commodity prices and the fourth quarter of 2020. We decided to keep a frac crew busy, leaning into 2021. We have an advantage with our access to the Gulf Coast demand market. The recent LNG exports are at an all-time high. Considering the current weather and commodity prices, we need to optimize our leverage. Dan shared our low cost and high margins. It's important to provide an outlook for the fourth quarter and beyond, ensuring we don't have disappointing quarterly results in the future.

Derrick Whitfield, Analyst

Thanks, Jay and Roland. That certainly makes sense. As a follow-up, referencing slide six, you were clearly impacted by several uncontrollable events in Q3. As you look out to Q4 and into 2021, how do you envision the shut-in metric trending over that period?

Roland Burns, CFO

That's a good question. A large impact is always simultaneous operations, which happens when trying to protect your offset production from frac activity. Realistically, I think the shut-in number is probably around 5%. If we maintain a consistent program, it could stay stable and not experience major fluctuations. Factors like power issues or pipeline issues may arise. In September and October, we withstood gas from the market as a major producer in the Haynesville Basin, as the market struggled with storage levels. This responsible action allowed the market to recover more quickly and allowed us to realize better prices shortly after.

Jay Allison, CEO

You may not see the influence from the private equity-backed Haynesville players, but they will experience similar shut-in issues. Comstock recently expanded its acreage by about 4,000 acres, totaling 309,000 acres. Our diverse drilling program across Texas and Louisiana minimizes exposure to shut-ins. Thus far, we anticipate a 5% rate for our activities considering our spatial spread and respective modeling and guidance.

Roland Burns, CFO

We haven't focused much on it earlier, Derrick. However, our efforts in 2021 will be directed toward minimizing gas sold at Perryville in order to mitigate the impact of base indexing prices from our basin.

Derrick Whitfield, Analyst

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

Jay Allison, CEO

Good morning.

Dun McIntosh, Analyst

Good morning, Jay. Thanks for providing detailed insights so far. I had a question regarding leverage. Understanding the pickup in activity, targeting leverage can be slightly easier from the EBITDA side. Given the new program, where do you see leverage heading in 2021 and 2022? We have talked about 2.5 times at the end of next year, but getting down to under two times. Will this get you there faster?

Jay Allison, CEO

Yes, it does. Roland shared some insights earlier, and we will delever faster thanks to market demand and prices at Henry Hub. The sole reason we would consider adding a rig or accelerating well completions is to expedite our delevering process. Roland, do you have a more specific number?

Roland Burns, CFO

Yes, as mentioned earlier, we're close to achieving that two times target by 2022 with our current plan. Investing a bit more in 2021 allows us to hit that goal rather than lagging behind if we receive a more stagnant production profile. It's been erratic for the company, with growth of 34% in 2019 dropping to 2% this year. Moving back to more sustainable growth levels of 6% to 8% allows us to balance our goals of EBITDAX improvement, leverage ratio reduction, and overall debt reduction while generating free cash flow.

Jay Allison, CEO

Ultimately, our goal is to reset the program for the fourth quarter and then over 2021 and 2022. This involves leveraging our position and reflecting the success of our locations and the profits we generate.

Derrick Whitfield, Analyst

Thank you. For my follow-up on your mentioned increase towards higher profits, what are the driving factors behind that decision? Is there further emphasis on EUR or bringing volumes online faster in the face of the anticipated higher price environment?

Dan Harrison, COO

Yes, it is Dan. The primary driver is EUR-driven which aligns with our performance outcomes. When we returned to larger jobs earlier this year, we saw lower gas prices and anticipated a 5% reduction in EUR's. However, we've noticed slightly higher reductions of 8-10% for wells in specific areas. When gas prices return to the $2.93, $3.10, and $3.20 ranges, we observe higher PV-10 values, indicating that it's advantageous to spend a little more upfront. We aim to keep all completed well costs under $1,000 to $1,050 better performance.

Jay Allison, CEO

It's a relevant question. We intentionally set our bookings to lower amounts, testing lower proppant amounts due to low gas prices. We took the necessary steps to reflect the return to a stronger pricing environment while trying to save money upfront. With the gas prices rising, it's prudent to adapt our approach and spend a little more in order to achieve better performance and maintain leverage. We recognize that it's our responsibility, and we are transparent about this matter with all stakeholders moving forward.

Derrick Whitfield, Analyst

Thank you.

Umang Choudhary, Analyst

Hi, good morning. You mentioned that gas prices are driving decisions regarding EBITDA to meet leverage goals. Can you discuss the conditions which can prompt a shift toward lower activity and spending in favor of more free cash flow? Is there a particular gas price point that would lead you to reduce activity, and how has that price point shifted due to recent reductions in well cost?

Roland Burns, CFO

Gas prices heavily influence our decisions. If gas prices underperform the futures market expectations, we would reassess our spending to maintain our free cash flow goals. As of now, we believe there is comfort in the $3 pricing area for 2021, but if this changes, we would reassess. We have also structured our operations in a manner making us flexible to adapt to varying circumstances. Ultimately, we aim to pursue our goals consistently.

Jay Allison, CEO

Another aspect to note is our very low long-term drilling and transportation commitments. Our acreage is primarily held by production, meaning our CapEx budget is driven internally by our requirements without external pressures.

Roland Burns, CFO

We'll remain vigilant about potential price changes. As seen this year, we can react swiftly to maintain our performance by adjusting our plans with no long-term obligations driving us to drill unnecessarily.

Jay Allison, CEO

The challenge for us lies in maintaining consistent production quality. Our company boasts an impressive 30-year inventory of well locations, greatly enhancing long-term growth potential. While shifting our gaze toward the current market, we must remain aware of the established operational advantages and strengths that position Comstock favorably moving forward.

Umang Choudhary, Analyst

Thank you for the insights.

Kevin Cunane, Analyst

Good morning. Just a quick question regarding 2021 expectations. You have increased your growth guidance significantly. What are you seeing in terms of non-operated spending for the year? Are you observing any of those private equity-backed companies gearing up for higher production growth next year?

Roland Burns, CFO

Yes, we have limited insights on other companies. Our non-operated projects account for a small portion of our budget, and we typically seek to reduce that number in favor of acreage trades. Recently concluded acreage trades with GeoSouthern and Indigo improved our position significantly without increasing non-operated activity. We expect roughly $35 million to $40 million budgeted for non-op activity, traditionally averaging 6-8% of our overall budget.

Kevin Cunane, Analyst

Understood. That's it for me. Thank you.

Phillips Johnston, Analyst

Hey guys, thanks. I wanted to ask about the 2021 program. Previously, your guidance suggested running six rigs throughout next year while targeting growth of 3% to 5% for around $450 million in CapEx. Now, it seems like you're calling for adding a seventh rig in the second quarter, increasing that spending towards $550 million, and expecting 6% to 8% growth. This change appears to largely hinge on stronger gas prices. Why not let those higher prices flow right to your free cash flow instead of increasing activity? If you plan to grow, are you considering hedging the majority of your production for both 2021 and 2022?

Roland Burns, CFO

Pursuing your suggestion could optimize our results for a short-term perspective, but we need to emphasize stability heading into 2022. Underinvestment could lead to no growth in 2022 and thus we seek to create a more balanced program in 2021 that provides sustainable results instead of focusing solely on short-term productivity.

Jay Allison, CEO

The timing is crucial. We want to balance our spending precisely while responding to the high gas prices, ensuring our market access advantages are properly utilized. We want to adjust our guidance to reflect success as we head into both 2021 and 2022. Additionally, we’ve hedged our production around 64% through 2021 and plan to hedge appropriately for 2022.

Roland Burns, CFO

We provide a disciplined focus on hedging, aiming for 60% to 70% coverage for the 2021 production period, and adjust our strategies to safeguard our financial position moving forward.

Phillips Johnston, Analyst

I'll switch gears a bit. There have been several large corporate mergers recently. What are your thoughts on consolidation in the Haynesville market?

Jay Allison, CEO

Our focus is on maintaining execution consistency. As we continue delivering our expectations, we would like to be a country of choice for Haynesville producers. A number of players reveal their long-term viability may require reevaluation. As long as we keep executing our strategies, opportunities for growth through consolidation could arise. However, we remain focused on our strengths with no intention to jeopardize our existing high margin positions unnecessarily.

Phillips Johnston, Analyst

Thank you very much.

Kashy Harrison, Analyst

Hi, good morning and thank you for taking my questions. I am interested in discussing corporate base declines. Given your shut-down over recent months, how should we view your corporate decline expectations moving forward?

Jay Allison, CEO

Historically, our corporate decline rate has hovered around 30% to 40%. For the next year, it’s probably closer to the higher end of that range, angling downwards towards 25%-30% over the subsequent year, eventually stabilizing.

Operator, Operator

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

Jay Allison, CEO

Thank you, everyone who stayed the whole hour on the call. We appreciate you taking the time to join us. Our goal is to reset the program for the fourth quarter of this year and for 2021 and 2022 to provide a strong foundation for the future. We want to optimize our access to the Gulf Coast demand market effectively. We appreciate your support and partnership. We believe brighter days lie ahead. As we focus on our operations, we are accountable to you. Thank you again.

Operator, Operator

Thank you, ladies and gentlemen, for your participation in today's conference. This concludes the program, and you may now disconnect. Good day.