Comstock Resources, Inc. (CRK) CEO Miles Allison on Q2 2021 Results - Earnings Call Transcript
Comstock Resources, Inc. (NYSE:CRK) Q2 2021 Earnings Conference Call August 4, 2021 11:00 AM ET
Miles Allison - Chairman & CEO
Roland Burns - President, CFO, Secretary & Director
Daniel Harrison - COO
Ronald Mills - VP, Finance & IR
Conference Call Participants
Derrick Whitfield - Stifel, Nicolaus & Company
Kasope Harrison - Simmons & Company
Charles Meade - Johnson Rice & Company
Umang Choudhary - Goldman Sachs Group
Bertrand Donnes - Truist Bank
Noel Parks - Coker Palmer Institutional
Leo Mariani - KeyBanc Capital Markets
Good day, and thank you for standing by. Welcome to the Comstock Resources Second Quarter 2021 Earnings conference call. At this time, all participants are in a listen only mode. After the speaker's presentation, there will be a question-and-answer session. [Operator Instructions].
I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and CEO. Please go ahead.
Again, thank you for the introduction. I know that we're reporting on the second quarter 2021 today. I know that. But we're super excited about what we see for the second half of this year. We advertised that we were front-end loading our capex in 2021 through the first half of the year, which we did. And now we see and actually have it today, corporate record high natural gas production and Comstock that we are selling at high natural gas prices.
The world of natural gas looks really solid with natural gas trading at $4 range plus this morning as I looked on the ticker, especially Haynesville dry natural gas that is a primary feedstock gas for LNG exports stage in Europe as well as to Mexico. Global demand for natural gas is very strong for industrial power generation as well as electrical demand for cooling and heating, while supply is low-to-moderate in part due to the disciplined use of capital expenditure dollars across the entire oil and gas sector, as you are all aware of in this earnings season.
Our corporate strength lies in our best-in-class, low-cost structure, which creates our high margins as well as the 1,900 plus net drilling locations within our 3000 to 323,000 net acre Haynesville/Bossier footprint, which we operate 91% of. One of the major tasks in 2021 was reduce our cost of capital, which we took mighty steps forward with our 5.875% senior notes being issued in the second quarter 2021. We do feel the wind in our sails as we look at the third and fourth quarter of 2021 and 2022 and want to recommit to you with our goal of reducing our leverage ratio to less than 2x at the end of 2022 or before if possible.
With the refinancing in place, we reduced our interest costs per mcfe by 25% this quarter to $0.36 and are committed to continue working to reduce that number by year-end 2021, if possible. The denominator of Comstock is our consistent drilling results quarter after quarter after quarter in a Tier 1 Haynesville/Bossier region, which speaks volumes about all of our departments, especially our operations department. And through our quality Haynesville/Bossier rock, that we have decades of that quality rock lift to drill.
I know that, that denominator is why Jerry Jones and his family invested $1 billion in Comstock since August 2018, and we believe that is why you, the bondholders, banks and equity owners buy Comstock, proven rock quality, proven results over many, many years.
Now I'll start the formal second quarter 2021 results. Welcome to the Comstock Resources Second Quarter 2021 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 presentations. There, you'll find a presentation entitled Second Quarter 2021 Results. I am Jay Allison, Chief Executive Officer of Comstock. And with me is Roland Burns, our present office -- Operating Officer; and Ron Mills, our VP of Finance and Investor Relations.
If you go to Slide 2, please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within a meaning of securities laws. While we believe the expectations and such statements to be reasonable, there could be no assurance that such expectations will prove to be correct.
Now if we'll go over to the second quarter 2021 highlights. We cover the highlights of the second quarter on Slide 3. In the second quarter, we reported adjusted net income of $55 million or $0.22 per diluted share. Production for the quarter averaged approximately 1.4 bcfe a day and was 98% natural gas. Our average daily production for the quarter was 8% higher than the first quarter of 2021 and 6% higher than the second quarter of 2020.
Revenues, including realized hedging losses were $325 million, 40% higher than the second quarter of 2020. Adjusted EBITDAX of $251 million was 55% higher than the second quarter of 2020. Operating cash flow for the quarter was $196 million or $0.71 per diluted share. For the quarter, we generated $20 million of free cash flow as the preferred dividends, increasing our year-to-year free cash flow to $53 million. That's a good start toward reaching our annual free cash flow generation goal of over $200 million. With the stronger commodity prices we're seeing in the second half of the year, we now expect free cash flow to come in well above that goal of $200 million.
And lastly, we completed the task of refinancing all of our higher coupon senior notes in the second quarter, which substantially reduced our cost of capital going forward. If you turn over to Slide 4, we recap the refinancing transaction, which closed on June 28. We issued $965 million of new 5.875% senior notes, which are due in 2030. The proceeds from the offering were used to redeem the remainder of our 9.75 quarter bonds. The refinancing transaction reduced our reported annual interest expense by $33 million, and we will save $28 million in annual cash interest payments.
Combined with the March refinancing that we did, our annual interest payments were reduced by $48 million. The lower cash interest expense will also drive significant improvements in our cash interest costs per mcfe produced, as I mentioned earlier, on a pro forma basis, assuming the refinancing was completed at the beginning of the quarter. Our second quarter interest cost for mcfe would have been $0.36 per mcfe as compared to a $0.48 rate in the first quarter.
In addition to lowering our cost of capital, we also improved our weighted average maturity of our senior notes to 7.6 years, up from 6.3 years. I'll now turn it over to Roland to review the financial results for the quarter in more detail. Roland?
All right. Thanks, Jay. On Slide 5, we summarize our reported financial results for this recently completed second quarter. We had a solid quarter, and it was driven by that 6% production increase in combination with stronger oil and gas prices than we had last year. Ore production for the second quarter totaled 100 -- our total production for the second quarter totaled 124 bcf of natural gas and 362,000 barrels of oil.
Like Jay said, this was 6% higher than we had in the second quarter of 2020, and it's an 8% increase over where we were in the first quarter of this year. Our oil and gas sales, as a result, including the realized losses from our hedging program, increased by 40% to $325 million. Oil prices averaged $55.82 per barrel, and our gas price averaged $2.46 per mcfe; both of those numbers, including the impact of our hedges. Natural gas prices were 31% better than we realized last year in the same second quarter of last year. Remember that NYMEX -- the NYMEX contract for the quarter only averaged $2.83. So I know the recent run-up in gas prices is really -- you'll really see those numbers starting in July forward.
Looking at the cost side, our production costs were up about 6%, kind of matching the increase in production. Our G&A was down 5%, and our noncash depreciation, depletion and amortization was up 18% in the quarter. Our adjusted EBITDAX came in at $251 million; it's 55% higher than the second quarter of last year. Operating cash flow was $196 million, 67% higher than the second quarter of 2020.
We did report a net loss of $184 million in the second quarter or $0.80 per share, but that was all due to a very large mark-to-market loss on our hedge contracts of $205 million and a $114 million charge related to the early retirement of the senior notes from our June 28 refinancing transaction. Adjusted net income, excluding the mark-to-market unrealized hedging loss and the loss on early retirement of debt and certain other unusual items, was a profit of $55 million or $0.22 per fully diluted share.
On Slide 6, we summarize the financial results for the first half of this year. For the first six months of the year, production totaled 241.5 bcfe. That includes 688,000 barrels of oil, and that's about 1% lower than our production for the first half of 2020. But our oil and gas sales, including any realized hedging losses were $657 million, which is 30% higher than the first half of 2020. Oil prices for the first half of this year have averaged $52.06 per barrel. That's 22% higher than last year, and our realized gas prices averaged $2.62 per mcf; both of those numbers, including the impact of our hedging, and that's up 34% over last year.
For the first half of this year, we've reported adjusted EBITDAX of $513 million, 41% higher than the same period last year. Operating cash flow was $403 million, 47% higher than last year. And then overall, for this period, we reported a loss of $322.5 million or $1.39 per share. Again, this was due to the charges for the early extinguishment of debt related to both the March and June refinancings and that mark-to-market unrealized loss on our hedge position. Excluding those items, our adjusted net income would be $118 million profit or $0.46 per diluted share.
Slide 7, we recap our hedging program. During the second quarter, we had 68% of our gas volumes hedged. That reduced our realized gas price that $2.46 per mcfe from the actual $2.59 for mcfe we realized from selling our gas production. We also had about 38% of our oil volumes hedged, which decreased our realized oil price to $55.82 per barrel versus the $61.25 we actually realized.
Overall, our hedging program resulted in realized losses of $18.8 million in the quarter. For the remainder of this year, we have natural gas hedges covering 976 million cubic feet per day, which is around 70% of our expected production in the second half of this year. 59% of those hedges are fixed price swaps, but 41% are collars, which give us exposure to the higher prices we're now seeing. For 2022 or next year, we have about 40% to 45% of our expected production hedged. And almost half of those or 49% are in the form of collars, which give us substantial exposure to the higher prices that we're kind of now seeing for next year.
On Slide 8, we summarized the shut-in activity during the second quarter. And we had a good quarter on this front. We had only 52 million a day shut-in during the second quarter, which is 3.8% of our production, and that came down substantially from the 6.4% we had shut-in, in the first quarter. There really were no significant disruptions due to storms or other matters in the quarter and the shut-ins that we had were very routine and related primarily to production we shut-in to conduct offset frac activity.
On Slide 9, we detail our operating cost per mcfe. We had a good quarter there. Our operating cost per mcfe averaged $0.54 in the second quarter, and that was $0.01 lower than the first quarter rate. Gathering costs were $0.25, taxes $0.08 and the other lifting cost in the field were $0.21, very comparable to the first quarter rates.
Slide 10, on corporate overhead per mcfe. That, again, came in at $0.05 in the second quarter. It's one of the lowest in the industry. And again, very, very consistent to what we expected and what we've had in the past. We do expect cash G&A to remain in this $0.05 to $0.07 range kind of going forward.
Slide 11. That's the depreciation, depletion and amortization per mcfe produced. That came in at $0.96 in the second quarter. It was $0.01 higher than the $0.95 rate we had in the first quarter of this year.
Slide 12. It's a picture of our balance sheet at the end of the second quarter, and it reflects our June 28 refinancing transaction, which closed right at the end of the month -- right at the end of the quarter. So we ended the quarter with $475 million drawn on our revolving credit facility, which is a $1.4 billion borrowing base. And we expect to continue to reduce that as we generate free cash flow the rest of the year. That's really -- free cash flow is being really designated to continue to reduce our debt.
We now have in total about $2.459 billion of senior notes outstanding. They're comprised of $244 million of the 7.5% senior notes, which are due in 2025. We assumed as part of the Covey Park acquisition, $1.25 billion of new 6.75% senior notes due in 2029 that we issued in March. And then the new $965 million of new 5.875 senior notes due in 2030 that were issued right at the end of the second quarter.
We currently plan to retire the 2025 7.5% bonds, probably sometime early next year, just using -- targeting the free cash flow that's generated and using that as a permanent debt reduction moved by the company. We do -- on Slide 12, you can see our new revised maturity schedule. And so you can see now that our weighted average maturity of our senior notes is now 7.6 years after the recent refinancing, right at the end of the second quarter. So we're in great shape on the maturity schedule. And as Jay pointed out, have substantially improved our cost of capital and generated substantial annual interest savings on what otherwise would be dollars that would have to go for fixed charges on our debt service.
So we did end the quarter with about $20 million in cash on the balance sheet. So our current liquidity is at $945 million. Slide 13, we recapped the second quarter capital expenditures. So in the second quarter, we spent $165 million on our development activities and $154 million of that relates to our operated Haynesville shale properties. So we drilled 21 or 15.7 net operated horizontal Haynesville wells, and then we returned 16 or 14.2 net operated Haynesville wells to sales in the recently completed second quarter. We also spent about $10.9 million on nonoperated activity and other development activity.
In addition to funding our development program, we've also invested $7.6 million on leasing new exploratory acreage. Given the tremendous success of that leasing program, we have decided to increase our budget up to a maximum of $20 million to spend on putting new leases in to support our Haynesville shale drilling program in the future. As we're seeing very good opportunities to do that at attractive terms.
So right now, as Dan will go over in a minute, we're currently operating five operated drilling rigs for our 2021 program, and we see kind of maintaining those five as we look ahead into 2022. So we're at a very good consistent level, we think, which is right for the company.
So based on this current operating plan, we expect to spend about $525 million to $560 million on this year's drilling plan, which will drill 55 net wells and turned to sales about 48 net wells. This is a small increase from what we expected at the beginning of the year. Most of that is really due to changes in the timing of when completions happen and then also higher-than-expected nonoperated activity. We definitely are very focused on generating significant free cash flow. And with the current gas prices, we now anticipate significantly exceeding our original target of $200 million of free cash flow for this year. We'll use that incremental free cash flow to accelerate the delevering of our balance sheet.
So now I'll turn it back over to Dan to kind of report on operations.
Okay. Thank you, Roland. Flip over on Slide 14. You'll see the map outlined in the summary of our new well completions. Since the last call, we've turned 21 new additional wells to sales. The 21 wells were tested at rates ranging from 15 million cubic feet a day up to 32 million cubic feet a day with a 22 million cubic feet per day average IP rate. The wells at lateral lengths ranging from 4,580 feet all the way up to 11,388 feet, and we had an average for the quarter of -- or for this list of 8,251 feet. So in addition to the wells we have listed here, we currently have 13 additional wells that we have in various stages of completion.
Regarding the activity levels this past May, we did drop down from six to five rigs. That's where we are today, and we intend to hold our activity flat at this level for the remainder of the year and into next year. Our fiscal DUC count currently stands at 23 wells, and we're currently we're actively running three frac crews.
Over on Slide 15, as an updated DNC call stream for our benchmark long lateral wells. These are our laterals greater than 8,000 feet in length. Through the end of the second quarter, 73% of all the wells turned to sales this year have been long lateral wells. During the second quarter, our total D&C cost averaged $1,051 a foot. This represents a 3% increase compared to the first quarter. And is 2% higher than the full year 2020 total D&C cost.
Our drilling costs in the second quarter increased by 7% compared to the first quarter. This is primarily attributable to a lower average lateral length versus the first quarter, but still 15% less than our drilling cost in 2020. Our completion costs remained relatively flat with only a 2% increase from the first quarter. But we're still running 16% higher than 2020. And this is due to the large number of the smaller fracs that were pumped in 2020, which led to the lower cost last year, lower completion costs.
For the remainder of the year, we expect our completion costs will remain relatively flat, and we do not foresee any material increase in costs. So by building on our basin leading drilling performance and keeping our current completion cost in check, we expect to maintain our total D&C cost for our benchmark long lateral wells in this 1,025, 1,050 foot range.
Also, I want to add that we're currently drilling two, 15,000 foot laterals that we spud in June. This is the first for the company. We expect to complete these wells during the fourth quarter. We also have two additional 15,000 foot wells that we will spud later this month that will be completed in the first quarter of next year. These longer laterals are going to help bolster our efforts to further increase our lateral lengths and to drive down our credit costs; drive down the footage cost further than where we've been.
So that summarizes the operations. I'm going to turn it back over to Jay to summarize our 2021 outlook.
Okay, Dan, that's short and sweet. It's usually about ten pages, and we've condensed it. That's a good report and Roland, same here. We'll conclude before we open it up for questions. If you look at the 2021 outlook, I'd like to direct you to Slide 16, where we summarize our outlook for the remainder of this year. Our operating plan for this year is expected to provide for around 8% to maybe 10% production growth and most importantly, generate in excess as Roland said, $200 million of free cash flow and maybe a lot more than that.
Our primary focus this year is to improve our balance sheet, reduce our leverage and lower our cost of capital, which we've made great strides on that. Our June refinancing transaction was another significant step to reducing our cost of capital with the $28 million annual savings and interest payments. Now we will primarily focus on absolute debt reduction, and we'll seek to retire, as Roland said, our 2025 bonds with free cash flow that we generate the rest of this year. If natural gas prices stay at current levels, we would expect our leverage ratio to improve to less than a 2.5X at the end of 2021, down from that $3.8 million at the end of 2020. And based on our current plans and the price outlook, we'd anticipate our leverage ratio further improving it to less than 2X at the end of 2022. We remain focused on maintaining and improving our industry-leading low-cost structure and best-in-class well drilling returns with our industry-leading low-cost structure, our Haynesville drilling program generates some of the highest drilling returns in all of North America. Our large inventory of Haynesville/Bossier drilling locations provide us with decades of drilling inventory. We'll also focus on lowering our greenhouse gas emissions and are currently evaluating participating in one of the programs to certify our gas as responsibly sourced and we have very strong liquidity, as Roland mentioned, at $945 million.
So Ron, I'll now turn it over to you to give any specific guidance for the rest of the year. Ron?
Thanks, Jay. On the guidance page, we just update the guidance for the remainder of this year. Production guidance remains at the 1.33 to 1.425 bcfe per day number that we had previously provided. As mentioned on the call, our development capex guidance is $525 million to $560 million. And we anticipate on remaining at the five rigs we're currently running over the remainder of the year. And at the same time, as mentioned earlier, the leasing capital has increased to $15 million to $20 million as we continue to add acreage.
On the cost side, LOE, GTC, really all the cost items remain unchanged from the prior quarter. And so there's -- we continue to hit all of our targets on the cost side. With that, I'll turn the call back over to the operator to answer questions from our analysts.
[Operator Instructions]. Our first question comes from Derrick Whitfield with Stifel.
Thanks, and good morning all. With my first question, I wanted to focus on your revised 2021 capital budget. With the understanding that nearly 40% of the revision was focused on leasing, which is arguably the most accretive dollar you could spend, could you help frame the remaining components of the increase on the development side?
Sure, Derek. That's a good question. It's a modest increase despite overall. But it's really -- what we are seeing is given the higher prices in the Haynesville, obviously seeing more nonoperated opportunities. We've set a very high bar trying -- and said only the ones that have very high returns are we participating in and ones that have a lower return, we actually have been able to sell down to other investors.
Unfortunately, a lot of them have a very high return. So it's hard to not participate in those. So we don't really control that level of activity and don't get great notice on it. But given the difference between this year and last year, you can understand why that's happening. On the operated side, where we do control that, we have a lot of the actual dollars really depend on when you complete the wells. We have a consistent drilling operation now, and that's stayed relatively the same, and we've actually probably achieved a little bit quicker drilling times. So it's really the timing. That changes all the time based -- And so it's just really -- when did the completion dollars fall? Do they actually hit this year? Do they go into next year? It can actually be the difference between $10 million and $20 million very easily in our budget, and we're constantly looking at that.
I think to Ron's credit, we've also probably, in the past, kind of looked at our projects and put them into three buckets. The 5,000-foot laterals to 7,500-foot laterals, the 10,000-foot laterals and budgeted that way. And I think we've kind of developed now a very, very, very exact formula now that takes the exact footage and comes up with really a better estimate. And especially when wells fall in between those different numbers. So we do see that working really well now. And since we it's telling us kind of the numbers that he's given you guidance on. We want to be transparent and communicate that.
Yes. My only comment, there's efficiencies, we've managed them, but they've moved dollars forward. They probably move them forward quicker than we want. So we try to manage that by being very selective on non-op opportunities and then just managing, 96% of what we own is HBP. So we manage this drilling program. We've kept the rig count flat. I think Dan has done a really good job historically on the completion side, you can see that's pretty predictable now and in the drilling side. We've got a lot quicker. So you move a bunch of these wells forward. That's why we have more DUCs today than we normally have. But we did increase that budget a little bit, and some of that is just adding acreage, which we think will be accretive to Comstock in the future.
Great. Makes complete sense to me. And really, as my follow-up. I wanted to build on Roland's comments and focus really on the trajectory of your D&C cost per lateral foot. Referencing Slide 15, it makes sense to me that D&C costs are higher per lateral foot when you're drilling shorter laterals. As you look out into the second half of 2021 and further out into 2022 when laterals will approach 10,000 feet. How should we think about the trajectory of your D&C cost, assuming a flat price/activity environment?
Well, if you look at the 10,000 to 15,000 foot, member, we've got 215,000 footers. We think that, again, it's a little early to predict it, but we think those costs eloquently will be below $1,000 a foot.
Yes. A great example is looking at the first quarter and second quarter, where the first quarter happened to be dominated by wells that averaged over 11,000 feet. And you saw that -- you can see the impact on the significant savings there from the longer laterals.
So as we continue to get more long laterals into the mix, we can kind of go back to averaging closer to where the first quarter was, if we could have that type of lateral in excess of 10,000-foot lateral average length and the wells being completed.
Yes. So Dan, why don't you make a comment?
Yes. So we got to the comment about the longer lateral. So we've got a lot more longer laterals in the pipeline, especially if we're on the Texas side, where you're not confined by one, two, three sections, one of those three buckets. And obviously, that's our goal is to get longer. We already have several wells coming in at below $1,000 a foot. And if we can get that average up, I mean, we're going to get that number ever lower.
As far as performance, I think we'll still see some slight improvement there. I mean, I think we're ahead of the back in the Haynesville on drilling times. We've starting probably in the end of 2020 through today, we've shaved off an average of ten days off our drill times from, say, the 2018, 2019, early 2020 average. So that's already given us the numbers that we got here. And then you just got the cost increases from the market, I mean, service cost, what are those going to do? We think between now and the end of the year, I think those will be relatively modest. So but next year, at the higher prices, I mean, we know there will be -- there's going to be upward pressure on prices. It's just going to be how much?
Well, we'll see some inflation on steel and cement and kind of those products. I mean, we'll see -- we've kind of worked in the numbers a little bit of some inflation for service costs, not picked on the drilling side, but maybe the completion side.
Our next question comes from Kasope Harrison with Piper Sandler.
My first question is on gas differentials. So in Q2, you returned to your historical differential range of the mid- 20s. I was wondering if you could talk about your expectations into Q3 and Q4 and also into 2022, if I could recall correctly, you had some gas being redirected toward the Gulf Coast and away from Perryville, and I'd like to get a better understanding of the impact of the model from the new arrangements.
All right. Yes, that's a good question. And obviously, we had the benefit of the premium winter storm prices in the first quarter that that gave us a much attractive differential in the first quarter. Back to normal as we thought we would be for this quarter. Third quarter, we expect to be very similar. Fourth quarter is when -- what you alluded to is the -- hopefully, improved marketing opportunities with the Acadian extension becoming -- coming into service. It's still planned to come in service in October, and we hope to be able to move additional gas away from the Perryville hub, which is kind of -- that's kind of where you get this kind of $0.25, $0.24 kind of differential into a market that's probably potentially $0.05 better.
Now we already have a -- so we'll only be moving some percentage of our gas that way, and we've kind of expected. Like right now, 60% of our gas is really tied to that Perryville hub. So it's the major index price you look out when you're looking at us. That number actually drops down to 40%, kind of hopefully in the fourth quarter and definitely to next year. So that has the potential to start shaving the differential down. And so we don't really -- those are all moving markets. So we don't want to just give you an exact number because we can't because all those markets are -- could move in different directions, but we do know if today, you're going to pick up anywhere from $0.05 to $0.10 on that gas, we're able to move away from Perryville down to selling it at Gulf Coast Hub, including Gillis, which will be the new hub that's available to us, and that market is just now starting to trade and we'll get more clarity on where that hub is going to trade at.
That's great. And then my next question relates to cost inflation. You had already -- you had just shared some detail on some of the pressures that you're seeing today. As you think about 2022, do you have a rough guesstimate of how we should be thinking about cost inflation in aggregate? A large Permian player head thrown out 10%. And I'd like to get a sense of how you guys are thinking about it.
Yes. I think -- so just to start off with what we've seen to date, we really -- we have seen a few really small ones, and they've been really small, like 5% and less. So for this year, that's why I say, I think we're pretty good. Next year, based on where we think the markets are going. I think next year, we'll probably, on average, be a little higher. And I think 5% to 10% probably is a pretty good number.
We haven't got any indicators from any of our providers that anything really major is coming. I think just at the macro level, just a higher activity. We just -- you just have to know that it's there, but I certainly don't see anything over 10%.
No, and again, we see capital discipline. We don't see a whole lot of rigs, either, particularly on the natural gas side, I mean, there's 103 rigs, I think, drilling for natural gas in the United States. So we don't see that increase. I mean -- so if it was in a frothy days before COVID, you might expect a lot of new rigs stuff. I think right now, with this capital discipline, we're just are going to see runaway inflation on our side. Now cost of our commodity has gone up. If commodity price hadn't gone up, I mean, we probably wouldn't have as many rigs being utilized today, both on the oil side and the gas side. So I think it's going to be moderate, it will be controlled. And it will probably be in that 5% to 8% range. That's our number. And that includes, again, steel, includes cement, it includes tubulars, some inflation on those costs.
That's great. And then a final one for me, if I may. I just wanted to ask about consolidation. I just wanted to hear your latest thoughts on consolidation within the Haynesville/Bossier area, where your appetite currently is? Just any thoughts would be appreciated.
Well, I think a lot of the consolidation, I think, size is important, but I also think -- I think your high margins and your low-cost will probably be more important. And everybody is speaking that kind of the denominator is locations. I mean some of these companies that you have to consolidate because you're running out of locations. I think the beauty of Comstock is two years ago when we bought Covey Park for that $2.2 billion, and they were larger than we were we added those locations with our locations with the locations that we've been adding with this leasing program to have that 1,900 to 2,000 locations, and like Ron and Roland and Dan said, we've departmentalizing those to 5,000-foot laterals, 7,500, 10,000 foot. So if you're looking at Comstock needing to do some type of M&A for locations, you can X that box because we don't need to.
If you're looking for Comstock to up their management, particularly from the drilling side and completion side, I mean, we drilled and completed more of these wells than anybody. So you probably don't need to. I think the only reason that we would do any M&A transaction is that the acreage is equally as valuable and our cost structure materially improves. And quite frankly, the Jones family owns 60% to 68% of the company, we would have to be blessed by them because I think what they've invested in right now is delivering great returns period. I don't -- size is important. But the footprint that we have or the Gulf Coast, with the demand for LNG to Asia and Europe. And with the lack of farm transportation commitments that we have and the high margins. I mean, we're not seeking to do something just to get bigger, period. We've -- we're way beyond that. We're in great shape, our maturity schedule. We were fighting that for a while. The expensive bonds, we were fighting that for a while. The Series A preferred, we were fighting that for a while. The 30 million shares or so that was issued to private equity was kind of out there as an overhang. We've cured that. We've consolidated the personnel. We're not looking to do that again. We got through the COVID year with lower prices. We had stretched our RBL with the Covey transaction. Now we have $945 million.
I mean, we're sitting in a sweet spot with solid production upside, solid EBITDA growth and stronger-than-expected realized pricing and are hedging into 2022, you cannot like it. But I think proper management, with the balance sheet we have, I mean, half of our hedges in 2022 are swaps, half of them are collars. Some of those collars go to $6.00. I mean, we've averaged like $3.50, $6.00, whatever, but I think it's a safe program in 2022.
So no, we're not aggressively fishing or looking for anybody. Now are we opportunistic? Sure, we are. Sure, we are. But I think it needs to be colored in that line.
Our next question is from Charles Meade with Johnson Rice.
Jay, I wanted to pick up a little bit on the theme you were just touching on with locations and ask you about the Bossier. I think back, it was years ago, you guys drilled some of the first really good Bossier wells have really opened a lot of people's eyes. But since then, my impression is that you guys are really, really just focused on the Haynesville zone. And in the last couple of quarters, there have been a few capital markets transactions with other companies who have half of the remaining locations, or more than half of the remaining locations, in the Bossier. And so can you give -- in as much detail as you'd like, a view of how you see the Bossier versus the Haynesville, both for the industry as a whole in this kind of -- in this footprint of Northwest Louisiana East Texas and for Comstock specifically?
Yes. Charles, I don't know how many times we've met with you face-to-face-to-face and how many companies you cover. But behind closed doors, I think your name is nick -- nickname is Einstein. So to ask that type of question, it's pretty incredible because we hadn't brought it up. We didn't ask anybody to bring it up. We didn't ask you to bring it up, okay? The whole audience needs to know that. But if -- I'm going to turn this over to Dan because he's supposed to be the calm one but I want him to tell you about the two Bossier wells that we just hit, the best wells we drill in the quarter. Nobody brought that up. I think you sniffed that out. And then probably half of our locations are Bossier, and if you ask other outside consulting groups, they really love the Bossier. If you look at a vine IPO, half of their upside is Bossier. If you look at Indigo, it's Bossier. We don't really talk about Bossier. That is a great, great question. I won't color you with my crayon, I'll give it to Dan. So Dan, and you go to slide whatever, Dan and go over that. Charles, thank you.
Please not your crayon, Jay. Anything but the crayon.
It's a blue one, cowboy blue.
Yes. So Charles, if -- which I didn't mention it earlier, but on Slide 14 on the list of the wells, those two best -- the IPs we had at the bottom there on our income wells, which you can see on the map, they're further down south here in Sabine, Parish. Those are, in fact, two Bossier completions. There are the only two Bossier completions on that list. We do like the Bossier. Obviously, it's the southern half of the play is where the Bossier exists. And the two -- I think this was in the last quarter, the two longest laterals we have drilled to date are 12,500 and a 13,000. So that 12,500 foot test, which was a Jordan well. That was a Bossier right there on the acreage on the Desoto, Sabine Parish border. And also these next two 15,000 foot laterals we are getting ready to drill later this month, are going to be Bossier's. So we do like the Bossier. The Bossier is good.
Charles, remember, you go back -- we kicked off of the Bossier in 2015, when we announced the world, we're just going to drill Haynesville/Bossier wells. We drilled nine Haynesville wells in 2015. And in December of 2015, as you well know, we built the first Bossier well. This is a Jordan well. And it kind of -- it's parked all the interest as a public company. We have to report in detail, it did spark the interest and rebirth of Bossier play.
So we're really excited about these 15,000 foot laterals. They are now -- they will be challenging. I think we've got a great drilling recipe. Of course, the 15,000 foot laterals, we'll have to get back up the learning curve a little bit. I mean they're not routine by any means, like we drill in the other wells, but that's kind of our plan. As we get these 15,000 foot laterals down, we plan to develop much of our Bossier with those long laterals.
Yes. That's -- just to add one more comment on that, Charles, is that, that's one of the things we've been thinking about the Bossier, too, as we want to migrate to the 15,000 foot laterals the Bossier is relatively undeveloped in our acreage. And there's a lot more room to do longer laterals or we can convert a much higher percentage of our Bossier inventory into the 15,000 foot laterals that we probably can realistically on the Haynesville acreage.
So that's -- and that also enhances returns. So we've been thinking about that more long-term because we just have so many wells to drill and such a large inventory. It's been hard to go to all the different plays yet. But it's a great part of the inventory. And I think the market started to realize that and some of the best wells in the play that are coming out of the Haynesville operators are Bossier wells now.
Well, and some of the non-opportunities have been Bossier. So yes, it's very surfacing.
Well, look, that's a lot of great color, guys. I appreciate that. A blind squirrel finds an acorn every now and then. But let me ask another, a kind of more -- maybe probably less interesting question. I look at the strip and we've still got this $0.65 drop between March and April. And it's been there for a long time. I -- frankly, if you'd asked me a couple of weeks ago or a couple of months ago, I would have said, well, look, that's going to -- those are -- that spread is going to have to tighten. The calendar spread is going to have to tighten as you get closer. But it hasn't. And so I'm curious, does that shape of the curve and that steep drop we see in the fourth month or in April of 2022, does that affect any of your planning or any of your decisions either near-term or longer term?
Well, that's a good question. And I think that -- the nature of that is really just the speculation in the gas market and the -- probably the tightness of the market and the fear that gas could be really short in that -- those winter months there. The longer you go out on the gas curve, the less speculations out there.
So a lot of it is going to be out there until winter really kind of shows itself. So it's kind of hard to plan around that. I mean you could have said you could have looked at that last year and made the same comments that the first quarter of 2021 was going to be, we really want to try to get your gas online in January through March. It turned out not to be a great strategy because that's -- those are going to be some of the lowest price months of this year of 2021. So it's really hard to look at the curve and rail toward it.
We do see that overall, though, over the last month, you've really seen the 2022 futures prices improved greatly, where they had been stuck at a level that was below 2021 for a long time. So a lot of it is just the market trying to figure out what the supply demand is going to look like later this year, and they're still filling it out. So we feel great about the gas market. And producer discipline, it's been a big component.
Well, Charles, as you look at, I mean, the next seven months, we're looking on the strip right now. I mean, gas is 418 the way to 404, seven or eight months out, and then it dropped to that 337 rent. I mean, if you told me three months ago, I'd have 337 natural gas in the Haynesville, I'd be pretty happy. I like four better, but it looks pretty good.
So we did front-end load 2022. If you look at the hedges to make sure we have a really good quarter in the first quarter of 2022, same 2023. And I think the other thing we did, because of our balance sheet, I mean, I do think we properly risk-adjusted our hedges. In hindsight, I wish we didn't have any hedges, but that's not how businesses are run, I think, in a moment, yet to pull whatever the hedge is, which is a swap or collar. And I think we've made a good business decision, and that is to have half of 2022 in a swap, which is solid. In case something did go south, but then they also have the collar that if gas hits $4.00, $5.00, $6.00, we get a little bite at that.
And I think our budget is good. We've asked that question about our models. When you -- when we said that we have 5,000-foot, 7 -- 5,500-foot, 10,500-foot laterals, we have that in both the Haynesville and the Bossier. So when we start kicking off these long laterals in the Bossier, we also have those models out, too. And we can toggle this back if we need to accelerate a little bit and convert some of the DUCs into PDP, I think we're going to be able to do that. I think we're going to be able to pay off the Covey bond. If we can do that, then our interest cost for mcfe continues to drop.
It wasn't that many quarters ago, we were $0.52 per mcfe, and now we're $0.36. We need to get a two on that, not a three. So we're going to -- like when we opened, this third and fourth quarter, I mean, they look really, really good. I know we're talking about the second quarter. But the second half of the year, it looks like but we should really capitalize on all-time high corporate production here, natural gas production with a really, really favorable natural gas price.
Yes. We see the same thing, Jay. All that insight is helpful. I appreciate it.
Our next question comes from Umang Choudhary with Goldman Sachs.
My first question is on your plans on absolute debt reduction. As you mentioned, gas features are very favorable. And if it holds, you can potentially generate free cash flow of well over $200 million. You have $475 million outstanding on our credit facility. Can you talk to your plans to address the remaining maturities and once you pay down your borrowings on the credit facility? And also, if you can talk to your thoughts around cash return to shareholders and the right absolute debt level at which you plan to deploy cash back to shareholders?
Yes. Those are great questions. And we are -- now that we've kind of got the cost of the long-term debt down and got the maturities in a great spot. It's really focused on the debt reduction. We do have a significant amount of debt that we can retire the bank facility debt, obviously. And then the -- we kind of -- we purposely did not refinance the remaining bonds outstanding because we thought that was also a good target for debt reduction.
So our plans are sometime probably next year to redeem the remaining 7.5% bonds. We obviously want to create the free cash flow and we'll pay in the bank facility first and then retire those bonds next. And so that's -- that over the next couple of years, gives us a lot of repayable debt that can help us achieve our overall debt reduction goals.
If you look at the windshield, our goal in 2014, we gave a dividend. We're not nearly there in giving a dividend. But I think you have to look at the windshield and say, where are you going? And with these higher prices, I think we can get this leverage down. We get the leverage down. It's got a one handle on it, one six, seven, eight, just take a number, and we're properly hedged. Then I think it will be nice to have a board meeting and say, hey, you know what? These are real Benjamin dollars that are going to go back to the stakeholders are going to be not only a dividend, but you can do what the pioneers of the world is start doing a variable. I think that is absolutely a possibility within the Comstock structure because of where we're located. Again, the demand for our gas, our feed gas to Europe and Asia and the demand growth as far as these export facilities are being built and the fact that we haven't encumbered our guests with some kind of strange firm transportation commitments that are below market or minimum volume commitments at our onerous.
So we are absolutely looking at the long ball in the next 18 to 24 months. And at the same time, on our leasing program, every year, we drill 50, 60 wells, we try to replenish that with 50, 60 more locations. So that is the goal. Now I don't want to spook the bondholders, the equity owners, anybody. I mean, we are never going to be financially reckless period. You can forget that. We are going to be financially aggressive. And that debt paid down, and we've got these maturities long, it will have the bond owners, help the equity owners and have the analysts and help us. So we're all in the end kind of in the same barrel together. That's our goal.
That's helpful. And I guess my next question was around hedging. Can you remind us the minimum percentage of production you need to hedge for your covenant? And also I wanted to get your thoughts around future hedging.
Sure. Yes. Yes, we're currently required to hedge 50% of our proved developed producing reserves at each borrowing base redetermination. So that's twice a year. So whatever the next 12 months of -- now usually, if you look at our production outlook, 100% doesn't come from proved developed producing reserves at that time. So -- and the 40% of our expected production to no more than 45%, we do need to hedge in some form, it could be in the form of a collar in order to satisfy the credit facility as the covenant currently stands. So we're at those levels for already for 2022, if we choose not to put any more hedges in at all.
So obviously been a huge run-up in prices. And I think we think we're adequately hedged for next year. And so I can't tell you if we're going to add any more or not, but I don't think we'll be hedging at a real high percentage level of 2022 right now based on how we see the outlook.
Thanks for your question. Our next question from Bertrand Donnes with Truist Bank.
I was wondering, in the prepared remarks, you said you were going to hold production flat. And I just wasn't sure exactly with the lower spend in the back half, whether that might kind of drift down in 4Q and 1Q 2022 and then maybe back up in 2Q? Or maybe it will truly be kind of a flattish profile?
I don't think that you talked about holding production flat. We actually talked about that basically this year is kind of -- we're seeing about 8% to 10% growth in production, and we have not really set the goals for 2022 yet. And so we're --
Yes, in fact, that's what we said. On the final slide. I mean you'll see it's an 8% to 10% production growth. And that's what our operating plan calls for.
Sorry, I just meant the back half, I thought I heard you guys say that maybe towards the end, but either way, is the lower activity, though? Is there some sort of quarterly cadence? Or are you just -- you don't want to get ahead of yourself and talk about that yet?
Well, I think, obviously, yes, you're going to see the third quarter, I mean, that's kind of the -- the second half of the year is the higher production levels. So we'll see higher production levels than the second quarter level coming up in the next two quarters.
But that -- it's a good question. We're not going to try to pick production and drop it off. We're going to try to level it out in our model in 2022. I think we have management discussions on that, too. I think what we said today is that we actually -- we front-end loaded that capex. We know we have that. But we've got a lot of DUCs that we can complete. We can shift some capex dollars around to complete those DUCS. But today, with $4.00, $4.00, $10.00, $20.00 gas, I mean, we actually are at a corporate high -- we're record high natural gas production had Comstock, and we're selling at a high natural gas price.
But we're going to monitor that in 2022. We don't expect to have a big peak and then a drop off. That's not our goal either.
That's perfect. And then really, just my only follow-up. With the higher gas strip. I know you guys maybe have talked about cash taxes before being pretty far out there, but just want to wonder if you guys could revisit that.
Yes, no, I think we still have a lot of good tax attributes, which we are able to use. And so we don't really see cash taxes being something to really put on the radar screen for the next several years. And our goal really is to -- we try to maximize our taxable income to use up carry-forwards that we have that we want to be able to use before they expire. We have a little bit of -- just due to structure, have a little bit of state cash taxes. That's all we kind of see right now. But that's a fairly modest amount compared to the income we have.
Our next question comes from Noel Parks with Tuohy Bros.
Just had a few things. With the success you've had on the leasing side, I was just curious, were those leases that you had had your eye on for a long time? Were they something that expired and came available, just at this stage in the play's development, it's a pleasant surprise to hear that you still can put together significant additional leasing.
Yes. This is a result of the combination of Covey and Comstock. When you put the land groove together and then you see what's kind of floating out there, they would be accretive to us in the future. So that's -- and then we didn't go forward on those programs at all for a while until we had the consolidated management team together. And then we said, okay, here are what we call low-hanging fruit, in our opinion. So we go out and when we spent quite a few dollars on it. But we -- it's very favorable terms on the leases.
Great. And I was also just thinking about the comments you were just making. As far as overall efficiency in the cost environment, where do you stand as far as the contracts on your frac spread, do you have a horizon path, which you have to negotiate on rates? Or is there -- or sort of a built-in renewal available to you at what you're paying now?
Well, of course, part of it just to preface that number. We do have one new three-year contract we've locked in the pricing on the new Titan fleet. That's next year. That's -- probably goes into service in January. So that has been fixed for three years.
And then Dan, you can kind of talk about the -- we probably need -- in addition to that, we'll need one to two more frac crews.
Yes. So that's right. So we got the -- BJ has provided the kind of the all turbine natural gas fleet that will start. It's anticipated the crew will show up and start working about January 1, and it is fixed for three years, which we think in the current outlook, that's going to be a great deal for us. The other -- the conventional fleets, they typically -- we have cost -- their contracts, and they do run through the end of this year, but they have a language in there where they can make price adjustments depending on what the market is doing. So in that sense, they're not locked down, solid like this, like our natural gas fleet will be.
Got you. And the 32 million a day IP that you well that you had in the quarter. I was wondering, is that a record for the company? And I was also just curious kind of where you stand on choke management these days.
So no, that's not a record for the company. But I think our record for the company is up in the mid, I think, about $36 million or $37 million a day is the highest IP we've ever showed. I mean, obviously, we have wells capable of doing more. I think that's the highest we've ever reported.
Choke management, basically, we -- even more so in a higher price environment, we basically hold the rate flat at a high rate until they get down close to line pressure, then basically, we -- they'll start declining off from there. And that kind of front-end loads our production and gets us a better return versus let the well decline off from month, Month 1.
Great. So -- sorry. Go ahead.
Yes, we do tailor the choke management around the wells pressure performance and each well tells us what it can do. And there also could be other restraints such as how much production can you flow off of pad. So there's -- not every well can always flow optimally just because you may have only so much transportation or facilities, you don't want to overwhelm them. So we have to manage all those factors and deciding to flow rates.
Our next question comes from Leo Mariani with KeyBanc.
I was hoping you could help out a little bit with kind of your capex spend here. You certainly talked about it being more weighted in the first half of the year. Can you kind of help us with the next couple of quarters? Should third quarter be a fair bit less than second quarter? And I noticed you had kind of looks like just based on the plan for the year, kind of not very many completions in the fourth quarter. So is fourth quarter capex going to be down a lot. Can you just kind of help us with the trajectory on the spend?
Sure. And you can look at just the kind of -- when levels look at the drilling, and we were running more rigs through May. So there's more drilling activity in the first, really, January through May is six rigs, then down to five rigs for the rest of the year there. There's also a maybe a couple of months where we'd be actually be running four rigs because we're probably going to loan out a rig a little bit, again, just because the drilling times have been quicker and trying to manage overall how many DUCs you build up. So the drilling activity is definitely weighted to the first half. The completion activity is weighted more through the first three quarters. Dan, so, you might talk about how many frac crews we're running in the different quarters.
So we are currently running three frac crews. And right now, at the end of the year, we got dropping down to one to two frac crews in Q4. And that's basically what's the front-end load for the production profile this year. And that will be -- we obviously are looking at the current prices that we're at. And we do have discussions about do we want to try to pull some more of that forward potentially sometimes. But right now, we're dropping frac crews towards the end of the year. We're at three. We should be at one in December.
Yes. Purposely, one, when we set the budget to say, hey, we want to -- when you are fracking, you have more shut-in too. So it's kind of a -- just to optimize production in what's usually the better months, we kind of designed the program that way. And I think we still, right now, kind of sticking with that.
So okay. That's helpful. And I would imagine sort of the capex is going to follow all of that activity, as you've described here.
Yes. And I guess maybe just a follow-up. I think on the previous earnings call on first quarter, you guys had talked about kind of 3% to 4% production growth in 2020. Obviously, since then, we've seen gas prices move up materially, you're clearly growing a lot faster than 3% to 4% here in 2021. Do you have any just kind of early thoughts about how you would approach, say, a $3.50 gas price environment in 2022? Is that the type of environment where you guys would like to maybe leaning a little bit more or a little bit more growth just because the returns are so good on the drilling? Or how do you think about that?
We plan on keeping the same rig count, and we'll see what the efficiencies do on the drilling and completion.
Right. Yes. I think -- well, obviously, we set a goal for free cash flow. And again, it's kind of early for us to lock into the to the 2021 program yet. But right now, we're kind of assuming we're going to have these five rigs running and can achieve kind of that type of production growth you talked about with that program.
So, we'll continue to look at that. But a lot will depend on where we are. As we get the leverage down, we'll open up opportunities to have other decisions here. But we see the leverage coming down fast in next year, really being under 2X, been our goal for several years, and we definitely want to achieve that before we start spending it in advance.
All right. So really just the budget will be designed upon kind of maximizing a lot of that free cash flow and in to leverage targets then production is just kind of an output sort of -- right.
The production will be a factor, but it won't be the -- like absolute -- the absolute driver will be what maximizes getting to the leverage profile. We want to get -- we think we have all the tools to get there next year. And so they're right here. So we want to check that box, just like we wanted to get rid of those expensive coupon bonds. That was a goal. They're gone now. So now it's -- we're going to focus on overall debt levels and leverage. And obviously, balance the EBITDAX growth with debt reduction is the balancing act of leverage.
We want to save a lot of money in 2022 on interest expense per mcfe. I think we'll get more efficient in 2022 with loan laterals. Prices look solid. So again, it's the same rig count. It's just efficiencies. Those efficiencies, along with a higher price, of course, it corrects our balance sheet, it pays down our debt, fortifies our RBL, and we have really good growth because we have Tier 1 area. It's a simple story.
Thank you, and this concludes the question-and-answer session. I would now like to turn the call back over to Jay Allison for any closing remarks.
All right. Again, some of you that joined kind of the middle of the call. And again, we're excited about that quarter, but we're more excited about the remaining six months of this year. We get front-end load our capex. We advertise that. We do have, right now, as we speak today, corporate record high natural gas production at Comstock, and it's a good time to have that because we are selling at high natural gas prices.
So I want you to know that we've recommitted to clean up this balance sheet. We've got good models that are strong, a good operations department, and we're thankful that we have all of used backers. So, thank you.
This concludes today's conference call. Thank you for participating. You may now disconnect.
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