Comstock Resources Inc Q4 FY2020 Earnings Call

Ladies and gentlemen, thank you for standing by and welcome to the Fourth Quarter 2020 Comstock Resources Inc. 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 is being recorded. I would now like to introduce your host for today's program, Jay Allison, Chairman and Chief Executive Officer. Please go ahead.

Jonathan, thank you for giving us a warm welcome. As most of you know, our home office is in Frisco, Texas, which is just north of Dallas. Today, if you looked out of our windows, you would think that we were in snowy Alaska or reporting from the ski slopes in Colorado. In fact, Alaska is probably warmer than the recent subzero temperatures that we've seen here with the wind chill factor. Our offices have been closed for three days now, and probably only four of us are here today reporting from the office. This Arctic freeze in Texas in the Mid-Continent creates challenging days in the world of natural gas. We've experienced idle frac fleets and idle drilling rigs due to the freeze-offs, as well as record demand just to keep the power on in our homes. In fact, millions are still without power as we speak. With 99% of our reserves being natural gas, which is the cleanest fossil fuel, our world-class Haynesville/Bossier gas fields being located in close proximity to the Gulf Coast LNG market, major petrochemical plants, and the industrial demand corridors, I can tell you that Comstock is well-positioned to help meet the existing and future needs for predictable and reliable energy in America. Despite 2020 being such a challenging year, I'm pleased that all 204 employees of Comstock have delivered solid results for the year, and I expect 2021 to be outstanding. Thank you for trusting us as we continue to seek to close out every day as a stronger company. Welcome to the Comstock Resources fourth 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 results presentation. There you'll find a presentation entitled fourth 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, who is joining us on the phone. Please refer to slide two in our presentation. 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'll turn over to slide three, we will recap some accomplishments from 2020. The most significant accomplishment is our successful navigation of one of the most difficult years for our industry ever. Despite realizing $1.80 for our gas and $32.36 for our oil, we still were able to turn in profitable financial results excluding unrealized hedging losses. We completed an accretive $207 million equity offering in May, the first natural gas common equity offering since 2016. The offering allowed us to redeem our Series A preferred stock and save $21 million per year from the elimination of dividend payments. The 41.3 million shares we issued in the offering eliminated the need to deliver 52.5 million shares in the future for the conversion of the preferred. We also completed two successful senior notes offerings totaling $800 million to repay bank debt, increasing financial liquidity from $166 million to $930 million. We reduced our usage of our bank credit facility from 88% to 36%. We had another year of strong results from our 2020 Haynesville/Bossier shale drilling program. We drilled 55 or 46.1 net successful wells that we operate. We turned 54 or 40.9 net operated wells to sales with an average initial production rate of 25 million cubic feet per day. In 2020, we were able to lower our well costs by 16%. Our two-mile laterals, which Dan will talk about in a minute, averaged $1,026 per completed lateral foot in 2020 versus $1,215 in the prior year. This allowed us to grow our proved reserve base by 3% at a low finding cost of $0.66 per Mcfe. Despite having to use very low prices to determine our SEC proved reserves, they grew by 3% to 5.6 Tcfe. Our reserve additions replaced 159% of our 2020 production. If you go over to slide four, we cover some highlights of the fourth quarter. We resumed completion activities in the third quarter, and our natural gas production increased by 6% from the low third quarter level. The production in the quarter was still impacted by a high shut-in level of 6.6%, mainly due to actions we took in October to shut in 300 million cubic feet a day of our operated production in response to very low natural gas spot prices. We turned 22 or 16.4 net Haynesville wells to sales with an average lateral length of 8,899 feet in the fourth quarter. We are well-positioned for continued production growth in the first quarter of 2021 and throughout the remainder of the year. Our conservative operating plan for 2021 is focused on reducing our leverage ratio by both growing EBITDAX and reducing debt. We're targeting to generate over $200 million in free cash flow in 2021. The higher production and improvement to oil and gas prices allowed us to return to profitability in the fourth quarter. We reported oil and gas sales of $277 million. Our EBITDAX came in at $211 million, and we generated $155 million or $0.56 per share in operating cash flow. Our adjusted net income for the quarter was $35 million or $0.14 per share. Lastly, we ended the year with very strong financial liquidity of $930 million. So now I'll turn it over to Roland to cover our financial results in more detail. Roland?

All right. Thanks, Jay. On slide five, we summarize our reported financial results for the fourth quarter of 2020. Our production for the fourth quarter totaled 109 Bcf of natural gas and 340,000 barrels of oil. This is 11% lower than production from the fourth quarter of 2019. Our oil and gas sales, including realized hedging gains, were $277 million, about 10% lower than 2019 due to the lower production level. Oil prices in the period averaged $44.47 per barrel, and our realized gas price averaged $2.40 per Mcf, including hedging gains. Overall, our natural gas prices were up 4% in the quarter, and our oil prices were down a little bit. Looking at the cost side, our lifting costs were down 11% in the quarter, and our depreciation, depletion, and amortization and G&A were both down 7% in the quarter. Our adjusted EBITDAX came in at $211 million, or 10% lower than 2019's fourth quarter. Our operating cash flow was $155 million, which was 18% lower than 2019, and we reported a net profit of $77.5 million for the fourth quarter, or $0.30 per share. The net income for the quarter did include an $80.2 million unrealized gain from the mark-to-market of our hedge positions, driven by the change in natural gas prices since September 30. Adjusted net income excluding the unrealized hedging gain and certain other unusual items was a profit of $34.6 million, or $0.14 per diluted share for the quarter. On slide six, we summarize the financial results for the entire year of 2020. Our production for 2020 totaled 460 Bcfe, which includes 1.5 million barrels of oil. That's 49% higher than 2019's production, mainly reflecting the acquisition of Covey Park that we closed in July of 2019. Pro forma for the Covey Park acquisition, our production increased 2% year-over-year. Our oil and gas sales, including realized hedging gains, were $993 million, which was 21% higher than 2019. Oil prices, including hedging, averaged $40.88 in 2020, and our realized gas price, including hedging, averaged $2.07 per Mcf, which was 12% lower than 2019. Adjusted EBITDAX for the year was $722 million, an 18% increase over 2019. Operating cash flow was $521 million, which was 11% higher than 2019. Overall, we reported a net loss of $83 million for the year, or $0.39 per share, but that loss was entirely due to the mark-to-market unrealized loss on our hedge positions. Excluding unrealized hedging losses and other unusual items, we had a net profit of $49.6 million, or $0.23 per diluted share for 2020. Despite a year of very low oil and gas prices, we were able to have a profitable year, and we did not have any impairments or other write-downs of our assets, which is unusual compared to many other companies in our industry. That says a lot about the quality of our assets and our low-cost structure. On slide seven, we cover our hedging program. During 2020, we had 51% of our gas volumes hedged, which increased our realized gas price to the $2.07 per Mcf, as compared to the $1.80 that we actually received from selling our production. We also had 84% of our oil volumes hedged, which increased our realized oil price to $40.88 per barrel versus the $32.30 per barrel we actually received. Overall, our realized hedging gains totaled $134.5 million in 2020. With the continued strength in natural gas prices, we've continued to add to our hedge book. Since we last reported earnings, we've hedged another 90 million cubic feet of our production for the second half of 2021 and another 100 million per day for the first half of 2022. For 2021, we have natural gas hedges covering almost 900 million a day of our gas production, which is around 65% of our expected 2021 production. The weighted average floor price of our 2021 gas hedge is $2.51. Going forward, we're primarily focused on adding to our 2022 hedge position. We continue to target having 55% to 70% of our production hedged for the upcoming 12 to 18-month period. On slide eight, we recap how much of our production was shut-in during the last quarter. In the fourth quarter, we had 6.6% of our natural gas production shut-in, compared to the 7.2% we had in the third quarter. As we mentioned in our third quarter call, in early October, we voluntarily shut-in 300 million a day of our production during the first two weeks of October due to very low spot market gas prices. The remaining shut-in production in the fourth quarter was due to offset frac activity. We also had 2% of our oil production curtailed or shut-in in the quarter, which was a significant decrease from how much was shut-in earlier in the year. On slide nine, we detail our operating costs per Mcfe produced. Our operating cost per Mcfe averaged $0.56 in the fourth quarter, as compared to the third quarter cost of $0.55. Gathering costs were $0.26. Our taxes averaged $0.09, and our field-level cost averaged $0.21. On slide 10, we detail our corporate overhead per Mcfe. Our cash G&A cost in the quarter was $0.04 per Mcfe, which is down from the third quarter, primarily due to year-end accrual adjustments. We expect our cash G&A costs to return to a more normalized level of $0.05 to $0.06 going forward. On slide 11, we detail the depreciation, depletion, and amortization per Mcfe produced. Our DD&A averaged $0.94 in the fourth quarter, about $0.01 lower than the $0.95 rate we had in the third quarter. Slide 12 shows the balance sheet at the end of 2020. We currently have $500 million drawn on our $1.4 billion revolving credit facility, and we expect to use our free cash flow that we are targeting to generate in 2021 to continue to pay that down. We have just over $2.25 billion of senior notes outstanding, 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. With a quarter-end cash position of $30 million, our current financial liquidity stands at $930 million. On slide 13, we summarize our fourth quarter and full year 2020 capital expenditures. We spent $169 million on development activities in the fourth quarter, of which $151 million was spent on operated Haynesville shale properties. For the full year, we spent $484 million on all development activities, including $410 million spent on our operated Haynesville shale properties. We drilled 46.1 net operated horizontal Haynesville wells and turned 40.9 net operated horizontal Haynesville wells to sales in 2020. We also spent another $82 million in 2020 on non-operated wells and other development activity, and we spent a total of $7.9 million in 2020 on leasing new Haynesville acreage. Currently, we're utilizing six operated rigs for our 2021 drilling program, but we expect to drop one of our operated rigs later this year due to the faster drilling times that we're achieving as Dan is going to go over with his operating results. Based on our current operating plan for 2021, we expect to drill 51 net operated Haynesville wells and turn about 50.5 net operated wells to sales in 2021. At the end of 2021, we expect to carry forward about 17.9 net DUCs into 2022. We estimate our total development capital expenditures to come in between $510 million and $550 million, and we're also budgeting to spend an additional $7 million to $10 million on the leasing program. We remain focused on generating significant free cash flow and will continue to target over $200 million of annual free cash flow generation as we plan our drilling activity. On slide 14, we summarize our oil and gas reserves at the end of 2020. We grew our proved reserves from 5.4 Tcfe at the end of 2019 to 5.6 Tcfe on an SEC basis at the end of 2020. Our 2020 drilling activity added 366 Bcfe to our proved reserves, and we had 367 Bcfe of positive performance-related revisions driven by the strong well performance of our Haynesville wells. The positive reserve revisions more than offset negative price-related revisions, which totaled 86 Bcfe and related to using the low first of the month 2020 average prices to determine reserves. Our all-in finding costs for 2020 came in at a very attractive $0.75 per Mcfe or $0.66 if you exclude the price-related revisions. Our reserves were 99% natural gas, with 36% of our reserves being developed. 95% of our proved reserves are in the Haynesville/Bossier, while 2% are in the Bakken and 3% are in other regions. The PV-10 value of our proved reserves was $2 billion using the SEC prices of $1.99 for gas and $39.57 for oil. Using an NYMEX reference price of $2.75 for gas and $50 for WTI oil, which is more reflective of our current price outlook, the PV-10 value of our reserves increases to $4.4 billion, and the quantities of proved reserves with those prices would increase to 5.8 Tcfe. In addition to those proved reserves, we have an additional 2.4 Bcfe of approved undeveloped reserves, which are not included in our proved reserves as we're not currently expecting to drill those within the five-year window required by SEC rules. We also have another 4.6 Tcfe of 2P or probable reserves and 6.8 Tcfe of 3P or possible reserves for a total reserve base of 19.6 Tcfe. I'll now turn it over to Dan to cover the fourth quarter drilling results in more detail.

Okay. Thank you, Roland. If you flip over to slide 15, this is going to be an outline of our current acreage position, which has now increased in the fourth quarter to 323,000 net acres. We control the majority of acreage with a 91% operated position and have an average working interest in the acreage of 82%. We currently have 1,953 net future drilling locations identified on this acreage, with 93% of the acreage currently held by production. Since starting our high-intensity completion program in 2015, we've now turned 272 wells to sales with an average initial production rate of 24 million cubic feet a day. We're currently running a total of six operated rigs. We do plan to release one of our rigs in May of this year and continue with five rigs for the remainder of the year. We're currently running three frac crews and anticipate running an average of just 2.2 frac crews for the full year of 2021. We currently have 25 DUCs on our schedule, and we anticipate our DUC count staying in the 20 to 25 range for the remainder of the year. Over on slide 16, this is our latest Haynesville/Bossier drilling inventory as of year-end 2020. Our operated inventory currently stands at 2,214 gross locations and 1,719 net locations, representing a 78% average working interest on our operated inventory. Our non-operated inventory consists of 1,585 gross locations and 234 net locations, which represents a 15% average working interest on the non-operated inventory. On our gross operated locations, we currently have 485 short laterals, 799 medium laterals, and 930 long laterals. If you split these out, we have 52% of our locations in the Haynesville and 48% in the Bossier. This inventory provides the company with over 30 years of drilling locations based on our current activity levels. On slide 17 is a map outline and summary of the 20 new wells that we turned to sales since the last call. The new wells were mostly located on our East Texas and Southwest De Soto Parish acreage, and we did have one well completed over Elm Grove acreage. The wells were tested at rates ranging from 18 million a day up to 33 million a day, with a 24 million cubic feet per day average initial production rate. We drilled and completed our longest lateral ever during the fourth quarter at 12,716 feet on the Jordan 16-9-4 number one well, which is down in the Southwest Desoto Parish acreage. We are currently completing a 13,000-plus foot lateral that will be turned to sales during the first quarter, and this will be our new record long well at that time. On slide 18 and the next three slides, we present the drilling and completion cost trends for our different lateral length buckets. Here on slide 18, we show the drilling and completion costs for our long lateral wells, which have lengths greater than 8,000 feet. On our long lateral wells in the fourth quarter, we experienced a 5% increase in our total drilling and completion costs due to a 15% increase in our completion costs. This was primarily due to the resumption of pumping our larger frac design of 3,500 pounds per foot in the fourth quarter, after pumping our smaller frac design of 2,800 pounds per foot in the second and third quarters. We were able to offset a portion of our increased completion costs with lower drilling costs in the fourth quarter due to an increase in drilling efficiency. With this increase in drilling efficiency, we have reduced our drilling costs further in the first quarter and expect to maintain lower drilling costs for the remainder of the year as we drive our drilling costs down to historic lows. This will help to offset the higher completion costs that we anticipate as a result of increased industry activity and higher associated service costs. Since 70% of the wells we drill in 2021 will be long laterals, our cost performance in this category is a major driver of our drilling program's success. Due to the higher drilling efficiency, we are confident that we will be able to maintain our drilling and completion costs relatively flat in this 1,000 to 1,050 foot range for our longer laterals. Ultimately, the gas price environment and market demand for services will determine where our costs settle out in this range. On slide 19, we show the drilling and completion costs for our medium lateral wells, which have lengths between 6,000 and 8,000 feet. In the fourth quarter, we had a total drilling and completion cost of $1,126 per foot. This represents a slight decrease of 3% from the previous quarter. While our completion costs also increased for medium-length laterals due to resuming the larger frac design in the fourth quarter, we still achieved lower drilling and completion costs in the fourth quarter by driving our drilling costs down by 10% due to our increased drilling efficiencies. Similar to our long lateral wells, we have reduced our drilling costs further in the first quarter of this year and expect to maintain this lower drilling cost throughout the rest of the year. On slide 20, we present the drilling and completion cost trend for our short lateral wells, which are wells that have lateral lengths of less than 6,000 feet. As you see here, we haven't completed any short lateral wells in the last two quarters, by design, since these wells have a higher cost and inferior economics compared to the longer laterals. When we do drill our short lateral wells, we attempt to do so as part of multi-well pads with our longer laterals to reduce costs and enhance our returns. Similar to the longer laterals on the previous two slides, we have continued to substantially drive down our costs on our short lateral wells. Over the course of the last year, we have successfully converted many of the short lateral wells in our inventory to longer lateral wells via acreage trades with other operators and through some small bolt-on acreage acquisitions. To reiterate on our operations, we are confident we can maintain our current low drilling and completion cost structure by capitalizing on the drilling efficiencies we've achieved to date and building on these moving forward. These lower drilling costs will help to offset the higher completion costs we anticipate for the remainder of the year as a result of increased industry activity and the associated higher service costs. That summarizes things on the operations side. I'm now going to turn it back over to Jay.

All right, Dan, Roland, thank you. If you would, let's go to slide 21, where we'll summarize our outlook for what we believe will be a fabulous 2021. We remain focused on maintaining and improving our industry-leading low-cost structure and best-in-class well drilling returns. Our inventory, as Dan mentioned, with 1,953 net Haynesville/Bossier drilling locations provides us with decades of drilling inventory. Our operating plan for the year is expected to provide production growth and generate in excess of $200 million of free cash flow, as Roland pointed out. In 2021, we're focused on improving our balance sheet, as we've told everybody for months, reducing our leverage, and lowering our cost of capital. With current natural gas prices, we would expect our leverage ratio to improve to around 2.5 times at the end of 2021, down from 3.8 in 2020. With our industry-leading low-cost structure, our Haynesville drilling program generates some of the highest drilling returns in North America. We have currently hedged approximately 65% of our 2021 production to protect our high drilling returns. We have very strong financial liquidity of $930 million. So with that, I want to turn it over to Ron, who can provide some specific guidance for the rest of the year. Ron?

Thanks, Jay. On slide 22, we provide financial guidance for 2021. The updated guidance from our November call reflects the impact of the timing of our drilling and completion schedule, as well as the shut-ins that were discussed earlier in the call. Looking at 2021, our development CapEx guidance is $510 million to $550 million. This budget anticipates the release of one of our operated rigs in May, as Dan mentioned. We also anticipate spending another $7 million to $10 million on leasing activities. Our production guidance is 1.33 to 1.425 Bcf per day. Our lease operating costs are expected to average $0.21 to $0.25 per Mcfe in 2021, and our gathering and transportation costs are expected to average $0.23 to $0.27 per Mcfe. Production and ad valorem taxes are expected to remain in the $0.08 to $0.10 per Mcfe range, and our DD&A rate is expected to average $0.90 to $1 per Mcfe. As mentioned earlier, we believe our cash G&A rate is expected to return to a more normal level of $0.05 to $0.07 per Mcfe. I'll now turn the call back over to the operator to answer questions.

Our first question comes from Derrick Whitfield from Stifel. Please go ahead with your question.

Thanks and good morning all and congrats on a strong quarter and positive outlook. Referencing Slide 8, you guys were fully impacted by several uncontrollable events in Q3 and Q4. I'd imagine Q1 could similarly be impacted by the current weather. At this time, do you have a sense of weather-related outages for Q1 and more broadly beyond Q1? How would you envision that shut-in metric trending based on your 2021 outlook?

Yes, that’s a great question, Derrick. Some of the shut-ins were voluntary. We didn't want to accept really low spot prices. Some of our gas that wasn't nominated, our swing gas, we decided to shut in during early October. But I think as you go into 2021, we haven't had those types of issues. We've had very good spot prices so far throughout 2021. In the last week, with all the events in Texas, we have seen incredible spot prices for our swing gas. Our marketing department has found opportunities, which are paying off well. However, we may see some shut-in production due to the weather. Up till now, we were at nearly full production, but starting yesterday, we've started to see some challenges where water haulers can’t service the wells due to road conditions in North Louisiana. We’ve already seen some shut-ins close to 20% of our normal production levels, but we expect that to last just a few days until road activities can resume.

Derrick, one of the positives is that our field personnel have done a fantastic job. Some of the wells that we had shut-in due to frozen frac crews were brought back online. Dan Harrison may want to comment further. Our field team has delivered great results amidst these challenges.

Yes. I would just add that our crews did a commendable job. Our frac crews were down since Saturday morning. We had a substantial amount of gas that we brought back into production during the spike we saw in prices from Saturday through Tuesday. Currently, we’re beginning to notice effects due to road conditions hampering our operations, but we trust that this is only temporary.

So, as Roland mentioned, while our prices will likely be higher, I don’t think it will have a large negative impact from shut-ins. If anything, I expect the outcome to be more positive.

Additionally, it's important to consider that under normal circumstances, we typically see 3% to 5% shut-in levels due to completion activity. What's unusual is when we go to 6% or 7%. Ultimately, we'll see how Q1 shapes up, but we believe it might result in a very positive outcome overall.

We had to manage through significantly abnormal circumstances in 2020 due to COVID-19 and multiple storms. Entering 2021 with weather issues, the demand performance of our field teams suggests that we will likely see positive results. As we mentioned earlier, LNG pulled back due to the weather events. The governor of Texas asked Freeport and Corpus Christi to conserve gas to keep homes warm, which further highlights the demand challenges we face. We are strategically positioned near the Gulf Coast corridors, allowing us to offer competitive pricing while maintaining the quality of our product. Thus, our capabilities and positioning afford us significant advantages in meeting this demand.

Guys, thanks for the comprehensive response. As a follow-up for Jay, given the constructive gas backdrop and your recent success in adding acreage in the quarter, can you comment on the current state of the acquisition and divestiture market?

We expect further consolidation in the industry. Wall Street is tightening constraints around material production growth. Companies need to drop leverage ratios and banks' borrowings. The new norm should focus on cleaner energy, which is presumably why we’ve seen significant investment from key stakeholders in Comstock. Bigger players must maintain high-quality assets with low costs while adhering to disciplined growth, particularly in gas production. However, in the Haynesville specifically, we face challenges due to the presence of many private equity-backed companies without clear valuation metrics. Despite the challenges, we expect the M&A market to remain active as higher-quality companies increasingly refine their portfolios. We remain vigilant in our strategy, leveraging strengths while generating consistent free cash flow.

Thanks for the insights, guys. I appreciate your time.

Thank you, Derrick.

Thank you. Our next question comes from the line of Dun McIntosh from Johnson Rice. Your question, please.

Good morning, Jay.

Good morning.

I notice that in the 2021 guidance, you have CapEx and activity slightly down while production is poised to rise, despite calling it five fewer turn-in lines. Could you help elucidate what gives you confidence in that production outlook despite the reduced returns? Is it due to an emphasis on higher-return areas, or the shift back to high-intensity completions? Any clarity on this would be helpful.

I'll let Dan respond to that, and I'll step back in if necessary. Go ahead, Dan.

We’re encouraged by the sustained improvements we've seen on the drilling side. We’re looking to drill longer laterals, which tend to yield greater returns. Additionally, our activities span a broad swath of our acreage, and our analysis showed that our completion performance improved after adjusting our frac sizes back to larger designs.

The biggest factor for our more efficient plan heading into 2021 revolves around drilling times. Wells now come on production faster, which means the capital we're spending is generating production more quickly.

To give you an example, previously, drilling a 10,000-foot lateral could take 28 to 30 days from spud to rig release. We've now optimized that to around 22 to 23 days. If we apply that improvement across five rigs throughout an entire year, we can turn more wells to sales, which results in more frac jobs and more production.

The longer we keep the rigs running, the quicker we can ramp up production without additional expenditure. The increase in drilling efficiency is pivotal in this equation.

This planning exercise is transparent; we owe you the assurance that our drilling methods enhance the overall efficiency of the company as we pursue optimal growth without unnecessary drag. We have potentially great production outlooks due to the recent performance improvements.

Thanks for that color. As a brief follow-up, one of your larger competitors is recently emerging from bankruptcy in the basin. How much exposure do you have to them from a non-operational perspective? I imagine you've been in communications with them, and what insight might you have into their plans this year?

Yes. They spun out about 50,000 acres as a part of their restructuring. While Chesapeake operates primarily in gas, they will likely keep two or three rigs busy. Although we've known them well in the past, we don’t have a lot of exposure to Chesapeake projects.

Indeed, our exposure to their operations is minimal, and their activity levels are not significantly different from what they were running prior to going bankrupt. We have limited direct interaction.

In fact, we recently purchased some acreage from them and have renegotiated terms to drill several wells successfully.

Understood. Thank you.

Thank you. Our next question comes from the line of Neal Dingmann from Truist Securities. Your question, please.

Good morning, Jay, and team. I just wanted to circle back to slide 15 for a bit more context. With the five rigs running this year and just look at the pooling of returns you're offering, can you elaborate on how you are managing production between various drilling areas?

Well, we're allocating a large percentage of our wells to long laterals. Between 75% to 80% of our budget will focus on drilling wells over 8,000 feet in length. At the same time, we drew from a wide geographic base to optimize production based on midstream capacities, preventing risks associated with oversaturation in a single area.

It’s essential to maintain a balanced approach. If we were to concentrate solely on areas with high production potential, we could risk midstream limitations that restrict our capacity to bring gas to market.

This blending approach allows us to maximize productivity without unplanned shut-ins. We've adopted this strategy in recent years, taking into account the need for flexibility.

Furthermore, our robust inventory mapping and rigorous assessing of production tiers ensure we can drill quality wells across our extensive acreage base. Our PDP component reflects our methodical approach to optimizing all available resources.

Thank you, all. I appreciate the in-depth responses.

Thank you. Our next question comes from the line of Leo Mariani from KeyBanc. Your question, please.

Hi, thank you. I have one question regarding the CapEx for 2021. Can you discuss what the expected quarterly cadence will look like?

Sure. While we typically provide annual guidance, the cadence for 2021 indicates that our first quarter will likely see the highest spending, while the fourth quarter will involve the lowest spending, and the second and third quarters will present moderate spending levels. So, expect a more dynamic approach during the year.

That is quite helpful. Appreciate it.

Thank you.

Thank you. Our next question comes from Umang Choudhary from Goldman Sachs. Your question, please.

Hi, good morning. I appreciate you fitting me in today. I wanted to gauge your thoughts regarding your non-operated partners? Is there any anticipation about their activity levels amid gas futures improvements? Additionally, are there certain price points at which you might consider escalating your own operations?

We cannot provide clear predictions for non-operated partners since they represent a minor segment of our operations. Our engagement with a couple of private companies remains limited. We perceive activities at Chesapeake to mirror their previous operational levels. Though we’re open to scaling our activity, we’re focusing primarily on growth profiles rather than immediate increases given current operational frameworks.

Ultimately, we operate 91% of our locations. Our focus is on consistent operations rather than a reliance on external entities. We strive to maintain our trajectory toward improved leverage and stronger cash flow.

That makes a lot of sense. I appreciate the insights.

Thank you. Our next question comes from the line of Noel Parks from Tuohy Brothers. Your question, please.

Good morning, everyone.

Good morning.

I wanted to inquire about the new acreage leasing you spent on in Q4, which was around $6.5 million. Was that part of a strategic acquisition you’ve been monitoring for some time?

Yes, we pursue opportunities tirelessly. Whenever the chance arises to acquire Haynesville acres that could enhance our laterals or yield solid future drilling locations, we pursue them.

Moreover, we're finding there's limited competition in this space, making it a significant opportunity. We’re dedicated to scanning the entire Haynesville region, seeking valuable lease opportunities.

Okay, I appreciate that. You previously mentioned the gas market environment. I'm wondering what your outlook looks like for the wider 2022 period. Do you think gas futures are lagging, especially given current demand dynamics?

We firmly believe that gas market dynamics are favorable for 2022. There's a persistent issue of a constrained supply that has historically pressured pricing. We expect a tighter market in the summer, even as some may question underlying demand fundamentals.

The 2022 production outlook might remain undervalued given the disconnect between current pricing and sustained demand. We intend to hedge smartly to protect our interests moving forward.

It sounds like an exciting opportunity ahead. Thank you.

Thank you.

Thank you. Our next question comes from the line of Kashy Harrison from Simmons Energy. Your question, please.

Good morning, all. Thanks for taking my question. Just a quick one for you. Can you elaborate on the percentage of gas in a quarter typically sold through the midweek versus the spot market?

A good question. We typically aim to sell around 75% to 80% based on index prices since that aligns with our hedging strategy. However, we prefer not to overexpose ourselves to the spot market, given potential uncertainties with production. Recently, we’ve been more exposed to the spot market, averaging about 35% lately, slightly lighter than usual. However, we’re prepared to respond to fluctuating prices and capitalize on favorable opportunities.

Precisely, our focus remains on balancing our commitments. On average, we'd like to align with the 70% to 80% index structure.

Thank you, and I look forward to seeing the realizations in your Q1 earnings.

We too are eager to see how it all materializes.

Absolutely.

Thank you. Our next question comes from the line of Phillips Johnston from Capital One. Your question, please.

Hello, everyone. Thanks. A question regarding your comments on the leverage ratio. From what you’ve seen, hitting that target below 2x by mid-22 is feasible if gas prices hold. With companies like Devon issuing variable dividends, could you provide insight into your Board's stance on returning cash to shareholders once the leverage goal is achieved?

Indeed, our objective has always been to establish a dividend-issuing structure. We previously issued dividends; however, market dynamics changed drastically in 2015. Establishing a reliable dividend structure remains a priority once we stabilize our leverage ratios and optimize our capital costs. Our commitment is invariably towards establishing a healthy, sustainable dividend for our shareholders.

Prioritizing leverage is imperative. Once we achieve lower levels, we can pivot toward considering what's more favorable—a variable or fixed dividend structure, which is still yet to be determined. We stand focused on our primary agenda of achieving solvency.

Absolutely. It's vital to lower our cost of capital and manage leverage effectively before taking concrete steps like introducing dividends. That remains our overarching strategy.

Understood. Thank you for the detailed insights.

Thank you.

Thank you. 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.

Just a housecleaning note. We've received a notice from the New York Stock Exchange thanking us for 25 years of partnership. They attached a customized listing emblem highlighting Comstock's milestone, which is exciting for us. If you have time, please check the emblem on our website or in the corporate presentation. Thank you for trusting us with your time and money. We aim to close every day as a stronger company. Stay warm, everyone.

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