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Coterra Energy Inc
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Thank you for standing by. My name is Cheryl, and I will be your conference operator today. At this time, I would like to welcome everyone to the Coterra Energy's First Quarter 2022 Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you.
Caterina Papadimitropoulos, Investor Relations. You may begin your conference.
Thank you, Cheryl. Good morning, everyone, and thank you for joining Coterra Energy's first quarter 2022 earnings conference call. During today's call, we may reference a updated investor presentation, which can be found on the company's website. Today's prepared remarks will include business overview from Tom Jorden, CEO and President; and Scott Schroeder, Executive Vice President and CFO. Also in the room, we have Steve Lindeman, Blake Sirgo, Todd Roemer and Daniel Guffey.
As a reminder, on today's call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers as well as reconcile to the most directly comparable GAAP financial measures were provided in yesterday afternoon's earnings release, which can be found on our website. Following our prepared remarks, we will take your questions. Please limit yourself to one question and one follow-up.
With that, I'll turn the call over to Tom.
Thank you, Caterina, and thank you to all for joining us this morning. By all measures, Coterra had an outstanding quarter. First quarter results were driven by a nice production beat and strong commodity prices. Our assets performed well as evidenced by our production coming at the high end of our guidance. We generated $961 million of free cash flow during the quarter and prosecuted our capital program with less than 30% of our cash flow from operations.
For the full year 2022, we currently project discretionary cash flow of $5.9 billion with our total 2022 capital program coming in at less than 30% of cash flow, leaving almost $4.5 billion in free cash flow. We were pleased to declare an ordinary dividend of $0.15 per share and a variable dividend of $0.45 per share for a total cash dividend of $0.60 per share.
Furthermore, we launched our share buyback program in the first quarter, buying in 7.6 million shares totaling $184. Taking together this resulted in a return of 69% of our free cash flow to our shareholders.
My remarks will cover a few high-level areas of interest. The outlook for inflation, the outlook for commodity prices and the role of the E&P sector in responding to the growing demand for oil and natural gas.
First, a few thoughts on inflation. As with all of our peers, we are seeing significant inflation in the oil field. Pricing for drilling rigs, completion crews, fuel, sand, labor, oilfield services and trucking are all moving upward. Lead times for ordering tubulars, compressors, electrical equipment, production equipment and line pipe are in many instances, 12 to 14 months from order to delivery. Premier drilling rigs and premier completion crews are in short supply.
Overall, we are seeing inflation moving towards 15% to 20% when comparing fiscal year 2022 to 2021. Although, we are pushing back with operational efficiencies, inflation is putting pressure on our capital guidance range.
For now, we are holding our capital guidance at the previously announced $1.4 billion to $1.5 billion range for the full year. There are, however, some bright lights. Wherever we can, we're powering our Permian drilling rigs with grid electrical power. All six of our Permian rigs are capable of running from grid power. 75% of our 2022 Permian drilling locations will be powered off the grid, which saves an estimated $50,000 per well or $4.3 million gross. We will also see significant savings from our first grid-powered frac crew, which arises late Q2.
Now a few words on commodity prices. For the first time in a decade, we are seeing support for oil and natural gas prices that is driven by long-term fundamental supply and demand outlook. For many years, any conversations on global oil supply ultimately pivoted to a conversation of what OPEC+ would do. Suddenly, the conversation is about the consequences of long-term underinvestment in replacing oil reserves and production. This has led to constructive thinking on long-term oil pricing by thoughtful, informed analysts and investors.
Natural gas and its vital role in world power generation has returned as a welcome hot topic. The world is ill prepared to meet ambitious climate goals and natural gas is a necessary part of the solution. That coupled with affordability and accessibility make natural gas and US LNG exports, a vital component to world energy supply. Energy security has returned as a top concern and US natural gas has a leading role to play in global energy security and US geopolitical influence.
We have seen solid support in natural gas prices, natural gas optimism and a serious discussion on the long-term role of US natural gas in the world arena. Coterra is well positioned to contribute to this critical need for US natural gas and US LNG exports. Finally, a few words on the E&P sector's ability and willingness to respond to increasing demand. The US E&P operator has proven to be remarkably resilient through times of crisis. It is through times of plenty that we have stumbled through lack of discipline and over investment.
As a consequence, our sector has created an environment of boom-and-bust cycles, each peak and trough setting the stage for the next cyclic response. Shale 3.0 and the investor standing around it has been a sea change in our business. Our investors have been clear. They want us to be disciplined in both high and low commodity price environments and be proactive in returning cash to our shareholders.
In a clear and unequivocal way, our shareholders have telegraphed that they want a changed behavior out of us. We have listened and have responded with conviction around the advised approach to disciplined investing. Now we find ourselves in a global energy crisis. Starting last summer, natural gas prices and much of the world spiked owing to demand that was brought on by underperformance of renewables and restricted supply into Europe.
Now the terrible tragedy in Ukraine and the loss of Russian oil and gas supplies have led to an energy crisis, unlike anything the world has seen in almost 50 years. In order for the US E&P sector to respond with increased US supply, we need well-thought-out regulation and policies that encourage responsible resource development and infrastructure build-out.
We need pipelines, which will take new legislation and cooperation from all stakeholders, including federal and state legislature and regulators, as well as the American public. Also, we need our investors to respond and encourage responsible growth.
Lastly, we need the American public to realize that we, as employees of US E&P companies are Americans first, and we will do everything we can to meet our patriotic duty. Cooperation between all parties, including the E&P industry is essential for global energy security and the long-term health of our industry.
Coterra stands ready to engage in these tough challenges. We have the assets, the organization, the talent and the wherewithal to do what we do best, solve difficult problems. And we will do that in partnership and conversation with our owners.
With that, I will turn the call over to Scott Schroeder, our Chief Financial Officer.
Thanks, Tom. Today I will briefly touch on first quarter results, shareholder returns and then finish with a discussion on guidance. During the first quarter, Coterra generated discretionary cash flow of $1.23 billion, the largest quarterly cash flow generated in the combined company's history.
The figure was largely driven by an 8% increase in realized Boe commodity price quarter-over-quarter and solid operational results. Accrued first quarter capital expenditures totaled $326 million, with D&C making up 96% of the total, while cash capital expenditures totaled $271 million.
Coterra's free cash flow totaled $961 million for the quarter, which included severance and merger-related costs of $31 million. Additionally, the free cash flow figure included cash hedge losses totaling $171 million.
First quarter total production volumes averaged 630 Mboe per day, with natural gas volumes averaging 2.85 Bcf per day, both at the high end of guidance. The company's oil production averaged 83.1 Mbo per day, 1.3% above the high end of guidance.
The first quarter performance was driven by a combination of non-operated production volume gains, positive well productivity and to a lesser extent, accelerated timing. The company exited the quarter with approximately $1.5 billion of cash, up from the $1 billion level at year-end 2021.
The company's combined net debt to trailing 12-month EBITDAX leverage ratio stands at 0.41 times at the end of the quarter. Liquidity stood at just under $3 billion when combining our cash position with our undrawn $1.5 billion revolver.
Turning to return of capital. We announced shareholder returns totaling 69% of the first quarter free cash flow, or 50% of cash flow from operations. The return was driven by three methods.
As Tom already indicated, we maintained our base $0.15 per share quarterly dividend, which provides one of the largest common dividend yields in the industry; second, we announced a variable dividend of $0.45 per share. Combined, our base plus variable dividend totaled $0.60 per share, up from our $0.56 per share dividend paid last quarter. Our total cash dividend is equal to 50% of free cash flow and 36% of cash flow from operations. Third, after announcing a buyback authorization of $1.25 billion in February, we repurchased $184 million of shares during the quarter. We repurchased 7.6 million shares at an average price of $24.16 per share. The buyback amounted to 23% -- excuse me, $0.23 per share or 19% of free cash flow. Entering the second quarter, the company had a 10b5-1 plan in place, and we will provide details of its second quarter share repurchase activity with our second quarter results in July.
We remain committed to returning 50-plus percent of free cash flow via the base plus common dividend and supplemental returns will come in the form of enhanced variable dividends, share buybacks or even debt reduction.
Lastly, I will discuss our guidance. In the release last night, we reiterated our full year 2022 production capital and unit cost guidance. Our second quarter total production guidance is equal to 605 to 625 MBoe per day with natural gas and oil volume guidance set at 2.725 to 2775 Bcf per day and 82 to 84 Mboe -- excuse me, MBO per day, respectively.
As previously communicated, our expectation is to generate second half volume growth. We are maintaining our full year 2022 capital investment guidance. However, we continue to see inflation headwinds, which could move us above the midpoint of our range. We intend to remain disciplined and have not added activity for this year.
While we are also seeing inflationary pressure relating to operating costs, especially in GPT and LOE, we expect to remain within our original unit cost guidance. G&A expense for the quarter was $1.48 per BOE, which included $0.54 per BOE or the $31 million previously mentioned related to severance and merger-related costs. Excluding these charges, G&A would have been below $1 per BOE and below the low end of guidance.
In summary, we remain committed to capital discipline and shareholder returns while focused on execution, maximizing return on capital and maintaining one of the best balance sheets in the industry.
With that, I will turn it back to the operator for Q&A.
[Operator Instructions] The first question is from Neil Mehta of Goldman Sachs. Please go ahead. Your line is open.
Yes, thanks. Congrats on the continued capital return. Tom, I want you to keep on weighing in on your view of the gas macro here. Obviously, the front month is close to $8, but the curve has strengthened quite a bit as well. Can you talk about -- do you see the fundamentals supporting the price that we see right now? And then tie it into your views on Waha as well, do you think -- do you worry about a disconnect there? And how are you positioning your business to mitigate this risk?
Well, Neil, I appreciate the question. I'll tee it up and then turn it over to Blake to comment on Waha. We are -- as you -- I hope are not surprised, we're very constructive on natural gas. Now of course, both commodities are backward-dated if you look at the strip, but we've seen support for natural gas well above what we've seen in recent years. And we see that as a response to fundamentals.
As I said in my opening remarks, I think there is a growing awareness of the critical need for natural gas and the market is responding accordingly. So we are very constructive on natural gas and really pleased to see the support it's achieved.
Now, you asked me, if I worry about Waha. Neil, I worry about everything. It's what I do. But we're not panicked. We think that the market will adjust and that a lot of the fears that are currently in the air are going to prove to be overblown. But, to that, I'm going to let Blake comment on Waha.
Thanks, Tom. Neil, when we look at our Permian gas, we already have about 45% on firm transport to the coast. The remainder is priced at Waha, but it's covered under firm sales agreements with our processors, that give us flow assurance well into 2024.
But really, when you look at Coterra, that Waha priced gas only makes up about 5% to 10% of our total Coterra gas portfolio. So we're evaluating all those new projects coming out of the basin, including those three that have already been announced that in aggregate, will add 1.8 Bcf a day of takeaway to the basin by Q4 2023.
So we're not against adding more FT if it makes sense, but we're going to view it through a really long-term lens. And we'll be hesitant to take on long-term commitments that could potentially destroy a lot of value for something we see as a short-term impact, but stay tuned.
All right. And thank you for that color. The follow-up is just around CapEx. It sounds like you guys are tracking towards the top end of that $1.4 billion to $1.5 billion, but still within the bracketed range. Is that a fair characterization of those comments? Again, reinvestment rate is very low, but just trying to make sure that you're not flowing off the top end. Thank you.
No. Yes, that was clear, I hope, on what we said, yes.
Thanks, Tom.
Your next question is from Nitin Kumar of Wells Fargo. Please go ahead. Your line is open.
Hi. Good morning, Tom and team. Thanks for taking my questions. I want to start with the gas side. You talked a little bit about Waha, but we heard from a lot of your peers about the LNG opportunity in the long-term, ways to participate in international pricing. Could you talk about what you are seeing out there? You have access to multiple markets. Are there any risks that you are seeing on the LNG market?
Again, Nitin, I'm going to turn this over to Blake, but we have studied the LNG markets hard. And one thing that I will say at Coterra is I'm very proud of our marketing group. They've been creative. They've been adaptive and they've been pretty nimble. And they've done a deep dive for us, and I'll let Blake summarize the marketplace as we see it.
Thanks, Tom. Nitin, first, I'll say, Coterra moves 350 million cubic feet a day, every day through Cove Point on a long-term LNG deal. So we absolutely have the wherewithal to do these long-term commitment and experience with LNG.
When we look at our assets, we've got three basins with multiple decades of high-quality inventory. So supply is not an issue for us. The challenge is, just economics. It's expensive to get to the coast. There's limited pipes to get there. So you pay a pretty good fee just to get there.
And once you get there, we're entering a really crowded LNG market. And that's really shown through in the deals that are being offered to the producers. So we're wrangling all that right now, trying to understand it, but we've got to find a long-term deal that works for our shareholders and creates value, but also works for the buyer. And we haven't found one yet, but we're going to keep hammering away at it.
Great. I appreciate the color, guys. And then, Tom, congrats on the fourth successful quarter of the buyback, you entered the second quarter with a 10b-5. It sounds like you are still leaning into that buyback program.
So if I could, how do you see the buyback program evolving? You've talked in the past about mid-cycle pricing? Are you seeing a change in the mid-cycle price? Is that why you're still buying back more shares? Just want to understand how this evolves from here.
Well, of course, Nitin, we filed that 10b-5 before we went into a quiet period. And we'll talk -- as Scott has said, at our next quarter release on what action it spurred, but we're -- I'll say this, Nitin, we are constantly having to rethink mid-cycle pricing. Classically, we entered the year with 55 and 275 being our definition of mid-cycle pricing, and for a certain period of last fall, that sounded fairly aggressive to us.
And now when you look at that today, you would say, boy, that's a pretty conservative view of mid-cycle pricing. We don't like to get in the business of publicly speculating on the value of a Coterra share. And with that, Scott, why don't you comment on this?
Yes. Sure, Tom. I think, as we said when we laid it out in just over history of legacy companies, it's just simply another arrow in the quiver to return capital to shareholders. And we will continue. We're not going to be granular and kind of explain where we put the price points in the 10b-5 plan. We were effective and we did execute on some of that, but we saw the -- what we’ve seen in the prices run up.
The outcome of the first quarter highlights exactly where we want to be, and that is, when -- the average of what we bought in that we've announced is $24.16. We got price with pushing $29, pushing $30 this morning on the announcement.
Again, we're not going to chase the thing up, but when we find opportunities and look at the relative valuation and intrinsic valuations, it will continue to be part of the return strategy, in certain periods in the cycles we’ll lean on it more heavily and in others we won't. But I agree with, Tom’s point whole heartedly. We got to, kind of, reassess what that mid-cycle price is right now.
And then -- and I'll just wrap that. We are extremely constructive on Coterra as you can -- I hope, will not surprise you. We're extremely constructive on our asset performance. We're constructive on our inventory, and we're really constructive on our positioning in the cyclic market in oil and natural gas. I mean, it's all where we want to be.
That said, when we launched the buyback, we want to pursue it aggressively, but we just feel like it ought to be tempered at some mid-cycle pricing. So the answer to your question is more about what do we think mid-cycle ought to be, rather than are we bullish on Coterra at our current share price.
I think with my opening remarks on the constructiveness on commodities and they're underpinned by supply-demand fundamentals, it's been a long time since I've been able to say that. And so, this mid-cycle pricing in the last couple of years has been a best guess of what the median is in a huge oscillating commodity market.
And now suddenly, it looks like we have some ground support. And so, I think we're all watching and rethinking how we ought to view what mid-cycle means. And that's kind of where we are. But we are extremely bullish on Coterra.
Great. Thanks. I feel good to be bullish and good luck for our execution.
Your next question is from Arun Jayaram of JPMorgan Chase. Please go ahead. Your line is open.
Good morning, Tom and team. I wanted to see if you could maybe give us an update, Tom, on just the broader supply chain. We are hearing about some challenges on the frac sand side in the Permian. But just wondering if you could maybe run through your management of the supply chain and what gives you confidence on being to execute in this kind of environment?
Well, I'll tee it up, and then I'm going to let Blake comment. We always have built relationships, Arun. I think you know that. We've had many times when relationships cost us a little and many times when they benefit. And we are long-term planners. We're long-term thinkers. And we like to have relationships through thick and thin. And so we don't wake up every morning in panic. We've got some really good partners out there in the oil service space.
Blake, why don't you comment on supply chain?
Yeah. Arun, specifically, starting with sand, we saw early in the year, things, especially in the Permian, we're getting pretty hectic out there in the sand market. And so we actually went out and purchased all our sand for the whole Permian program for the year. And then the Marcellus, we're under contract for SAM for the year. So we took that one off the table.
We've covered the majority of our big cost drivers, frac spreads, rigs, tubulars with contracts that get us through the end of the year. But we still have exposure in items like diesel, labor, trucking, we're subject to all those, and we watch them really closely. We've built in all the inflation we've experienced today in our projections, and that's what's reflected. But ultimately, we can't control the market or inflation. We can control our efficiencies and our execution, and that's where we're always laser focused.
Some of that you can see our average lateral length in the Permian is up 12% year-over-year. Our average development size is up 51% in year-over-year in number of wells. And as Tom mentioned in his opening remarks, we're really starting to bear the fruit of our electrification projects, and those are real savings, and we expect to extend those with our grid-powered frac fleet coming on this summer. So supply chain is a challenge, inflation is a challenge, but our op teams are up to it, and they're finding new ways to fight against it every day.
Arun, if I could just follow on with that. Blake mentioned two elements. One is cost inflation, but the other is just supply chain bottlenecks. And cost inflation, that's just out there and hard to fully predict. But we can do something about supply chain bottlenecks by careful planning, by ordering ahead, by making sure that we have conversations with our partners and let them plan, as Blake said, we did pre-buy our sand, and we are preordering a lot of stuff for 2023.
We're -- it's just remarkable the extension in lead time between order and delivery. So we're on top of it as we look into 2023 and beyond. And we're doing multiyear planning, and we got a good head start on this.
Great. And just my follow-up, Tom, you guys have always had a very dynamic kind of capital allocation program. And I was wondering, a lot of the program as we think about today, was based on a much different pricing environment. I think today, you're spending just under 50% of your CapEx in the Permian, 45% or so in the Marcellus and, call it, mid-single digits or in the upper single digits or so in the Anadarko Basin. But I was wondering how you think about adjusting the development plan in a much higher price environment where there may be some inventory that in a, call it, a $3 case at and get to, but maybe in the $5 that may make sense to take advantage of. So I was wondering if you could give us your philosophical thoughts on that question.
Well, in some sense, I'm going to answer it describing it barriers for the riches. One of the great things about having a deep inventory is we really can make decisions around capital returns and not worry about any our issues. So we do rank our inventory – and we're certainly going to fund from the best returns down. So a lot of that lower inventory stuff is still going to be lower in the ranking. But Marcellus, they are all competing for those top slots. And we are going to be aggressive in just waking up every day and putting capital where it needs to flow. And that's something on, you've heard from us for a long, long time.
Great. Thanks a lot, Tom.
Your next question is from Jeanine Wai of Barclays. Please go ahead. Your line is open.
Hi, good morning, everyone. Thanks for taking our questions.
Good morning, Jeanine.
Good morning. Our first question is just on the 2022 plan. Sorry to get a little bit in the detail here. But I think the expectation with that 22% would be back half weighted in both the Permian and the Marcellus and when we're looking at the 2Q guide, it implies flat sequential oil production at the midpoint, it's also flat versus the midpoint of the full year guide. So just wondering if you could talk about maybe any updated thoughts on how you're viewing oil during the second half of the year. And then on the gas side, maybe it's a little more straightforward because Q2 is down a little bit, but maybe any commentary on the gas side as well.
Well, I'll tee it up and then invite maybe Scott will want to comment. But we do see second quarter flattish and then we'll have a little bit of growth into Q3 and Q4. There is a little dip in the year, but that's just around project timing. It's around pad size. There's nothing organically problematic to it. As we get into longer laterals and larger pads, this is just nature of the beast. Scott?
Yes, sure. And what I would add is exactly what Tom said. It's just the timing, it's the cadence. We had some positives coming out of the first quarter that gave us more comfort in terms of guiding more of a flatter trajectory in the second quarter. But the plan, as I said in my remarks is still dominated. It's back-half weighted as it was. On the gas side, particularly on the Marcellus business unit, when you look at the cadence because again, very few rigs running, very few completion crews running. So it's just -- it's a lumpy profile. We will only have 35% of the footage turned in line by the end of the second quarter, which will again solidify that second half ramp that we are planning for. So no big changes, a little bit of positive that I alluded to in my remarks that gave us more comfort with the second quarter, and we'll watch the dynamic continue to play out.
Okay, great. Thank you. And then maybe just circling back on cash returns. Can you just maybe talk about how you set the 50% free cash flow payout level for the base plus the variable versus it was 60% last quarter. And is it really more about the absolute return rather than the percentage every quarter? Thank you.
Well, it's -- I wish I could tell you we had some formula or machine learning algorithm to do this, but we -- it's a judgment call. And this quarter, we were pleased to have a combined ordinary and variable dividend and exceeded what we paid last quarter, but we also took into consideration the progress we've made in our buyback and the progress that we hope to make on our buyback.
So, we did want to keep a little dry powder in terms of cash. But, Jeanine, it's a judgment call. and there's no absolute right answer. Scott, do you have any wisdom I missed there?
No, I think you covered it perfectly, Tom. The key thing was versus the first quarter when we didn't have the buyback authorization, that's why we leaned harder on the variable, having another -- again, not to overuse the analogy, arrow in the quiver, that played into the discussion. And that's why we landed it at 50% this time because, as Tom also indicated, we exceeded what we did last time at the 50% level.
Understood. Thank you.
Your next question is from Holly Stewart of Scotia Howard Weil. Please go ahead, your line is open.
Good morning. Gentlemen. Tom, maybe just appreciate the comments on the global energy crisis. I know you've spent some time in Washington as well as with other folks just pushing the global gas agenda. What can you tell us about your conversations? And maybe how do you see these global policies playing out?
Well, we've had very constructive conversations and thank you for that question, in Washington. But also, we were recently on roadshow and engaged with a lot of our owners, and those were really good conversations. And I will say that I hope you glean from my remarks that it's not just one string you control here.
Look, I think the solutions here are self-evident and I think everybody knows it. I just don't think we have the collective will to execute it. We need infrastructure. We need support broadly from our regulators, from our investors. We're not going to stray from our investors here. I absolutely going to stay close to our owners on this topic. We need support out of the American public, and we need the will to solve this problem. The American producers ready to do our part.
And I'll just say again, it is not a complex problem. That is perhaps the most discouraging part of this whole situation. We have the resources, US onshore and offshore to return to global dominance in terms of energy leader. We're seeding geopolitical influence in ways that are unnecessary and we need leadership. But we also need people to just come together and solve the problem, and we're ready to do our part.
And I think our owners are too. We're say, we're not going to stray from our owners. We're going to certainly be in constant communication with our owners. But we're not talking about returning to the -- I think irresponsible capital days of work, and a lot has changed in our business. One is a lot of our projects pay out in a very short amount of time. So we're not talking about years to pay out. We're talking about months on some of these projects. And so that's going to change your thinking on risk of capital allocation. But we just need some very thoughtful people helping solve this problem. But thank you for that question, Holly.
Yeah. Now those are some good points. Scott, maybe asking you one that hasn't been asked yet. There is an eight handle on gas this morning. So there looks to be, kind of, minimal updates on the hedging front here, and we're hearing, obviously, a lot on inflationary pressures. So I guess my question would be, can this price be ignored on the natural gas side for hedges?
Hi. The simple answer is no, it cannot be ignored. And we will continue, as we have in the past, we have a hedge committee. We were active again recently even in this week, and we will continue to lean in and monitor the market.
Great. Thank you, gentlemen.
Thank you.
Your next question is from Michael Scialla of Stifel. Please go ahead. Your line is open.
Yeah, hi. Good morning, everyone. On slide 11, you mentioned a new shale in the Permian. Just wanted to see if you could give any more color on that? Anything you could say about the two wells you've completed, what the returns look like and the potential inventory there?
Yeah. Mike, I'll handle that one. This really isn't a new shale in the basin. It's one that a number of other operators are drilling. It's in the Bone Spring section. And historically, we've drilled second Bone Spring -- excuse me, Third Bone Spring sand and Second Bone Spring sand, and it's a shale that lies in that Bone Spring section. It is a shale. It's a sand up in New Mexico, and then it goes into a shale in Reeves, Loving County.
We at Coterra, at legacy Cimarex, we drilled our first test in it in late 2019, brought it online in December of that year and had a very, very nice result. So we've tested in a number of places and have had outstanding success. We really brought -- or bringing a nice project on now that is four wells per section. We see this landing zone as probably four to six wells per section, and it adds significantly to our top-tier inventory, somewhere, I think adding five years of top-tier inventory would not be a stretch, just this landing zone loan. It's not -- it grades in quality, but it's really good. Second tier is really good here.
So we've been excited about it for a while. It's the first time we publicly discussed it, but we have results to talk about. And we're really looking forward to just adding this in our toolkit for generating and developing great return on capital.
Well, thanks for that. That sounds encouraging. Wanted to ask you on your -- you've pushed the number of wells per pad in the Permian to more than eight in the last few years from -- I think you were just a little over three back in 2018 to help improve the efficiencies. With that increase typically comes longer lag times between capital investment and cash flow. I want to see how you're viewing that trade-off in this inflationary environment. And do you think you're near the limits, I guess, is what I'm really getting at in terms of the number of wells per pad, or are you comfortable pushing that number higher?
I am very comfortable with pushing that number higher. Now yes, how I view it, Mike. And I'm going to be clear with you as you always expect to be. I view it completely through a lens of what's the best business decision. And I know from time to time that it's very difficult for the external world to understand lumpiness in production and the production cadence, that's not just smooth and consistently up to the right.
And I wish that were the way the world works, but it's not the way the world works. These larger pads really make sense from a capital efficiency standpoint, from a land disturbance standpoint, from a return on capital standpoint but also from an emission standpoint. By centralizing our facilities, we have the opportunity to reduce our number of emitters, centralize them and really deliver the cleanest barrel in the world. And so I think about it in terms of what's the best business decision and going to a larger number of wells per pad can be the best business decision. I mean it's not always the best business decision because it also extends your lead time from first spud to first production. But we -- the only answer to your question is, how do I think about it? It's the absolute best business decision. And I always take the approach that we're going to make good business decisions. And I'd rather explain a good business decision then react to a market that doesn't understand and so make a poor one. So that's the way we think about it.
Appreciate it, Tom. Thanks.
Your next question is from Matt Portillo of TPH. Please go ahead. Your line is open.
Good morning, all. Thanks for the question.
Hi, Matt.
ust one quick one from me. Tom, I know the team is always evolving its thoughts on completion design and spacing design across all three areas of operation. I was curious, as you've gotten a little more time to look at the Marcellus, how you're thinking about the completion and spacing design and when we might start to see some well results that would potentially change your views on the capital efficiency for that asset moving forward?
Well, I'll tee it up, and I'm going to turn it over to Blake. I am just so pleased with the technical integration that's going on at Coterra. In fact, there's a team in Pittsburgh today that's reviewing a lot of the machine learning that we've pioneered. Machine learning has become a really important part of our completion design and that's something I really look forward to discussing in greater detail in future years. But there's just such a great spirit of technical curiosity that's shared between our Anadarko, our Permian and our Marcellus business unit. And from that collaboration, everybody gets better. But Blake, why don't you just comment on that?
Yes. Just to echo Tom, you take the Permian, the Anadarko and the Marcellus and they all have their very unique challenges. And so they all have very unique solution sets that never get presented outside of that basin unless you have these teams that are cross-pollinating across them. And so that's bringing some really interesting discussions, some really interesting solutions that we would never see just looking over the lease line. Really, as far as completions and well spacing, we challenge that every day. There's lots of work going on in the Marcellus right now to run new models and look at things in a new way. And vice-versely, the Marcellus team is challenging the Permian team and the Anadarko team. So it'll be exciting to see where it goes.
And one quick follow-up on the financial side, maybe a question for Scott. Looking at the cash balance you guys have today, in excess of kind of the maturities you have through 2024, staring down kind of something north of probably $4.5 billion of free cash flow in 2022, given the recent strip move.
Just curious, I guess, as we kind of factor in the variable plus common dividend and look at the buyback, it looks like you still probably have another $1 billion or so of free cash flow to distribute. Just wanted to see how we should be thinking about that return mechanism, as we step through the rest of this year, given the upside to your free cash flow profile?
Yes, Matt, I think you're looking at -- I mean, if you go back to my prepared remarks, we got the base, we got the variable. We've got buybacks and I appreciate the fact that you did bring up debt. Is there a wedge of that, that goes to debt repayment?
We have the maturities in 2024, $1.3 billion. Again, we're not leaning in hard on that, but that's all going to be part of the equation internal and in the boardroom as to what we do. Obviously, the Fed is going to meet tomorrow, and we'll see what interest rates do in response to that.
But at the same time, what is that refinancing risk that's out there 24 months from now. Again, we've got an eye on that right now, while we're seeing this excess free cash flow, and everything is in play.
But keep in mind, we remain committed to at least 50% of that $4.5 billion coming back to shareholders, if that number stays and is solidified throughout the course of the year. Obviously, commodity prices would change. But as Tom in his remarks said, we're seeing kind of a shift here in terms of the system is set up for very positive prices for an extended period of time.
Thank you.
Your next question is from Doug Leggate of Bank of America. Please, go ahead. Your line is open.
Thanks. Good morning, everyone. Tom, thanks for getting me on this morning.
Hi, Doug
I appreciate the opportunity. I guess, my first question, I want to go back to the question about capital allocation and just understand if the change that appears to be emerging in long-term natural gas. And we're all aware of the short-term LNG constraints in the Gulf Coast.
But let's assume that we're resetting the long-term natural gas, does Coterra reconsider capital allocation back to the legacy Cabot portfolio in lieu of the Delaware? How do you think about what the opportunities that might reset for you within the portfolio?
Yes, Doug, we're looking at that now. We're getting a head start on 2023. But, yes, I would not be surprised to see us pivot capital into the Marcellus. It's a remarkable asset with remarkable returns. And as I said earlier, it's kind of an embarrassment of riches. We've got so many great choices and I challenge our organization to make our job difficult on capital allocation. And, boy, they're taking me for my word on that, we've got some really good options.
I guess, I hope Dan doesn't take this as a second question. It's kind of an add-on to the relative economics. But has that decision been augmented by the NOL situation as it relates to deferring cash taxes in the Marcellus. I'm just curious if that's part of the narrative.
Doug, this is Scott. No, that's not part of the narrative. Again, as Tom has alluded to many times, we're going to make the best business decision. And as we have alluded to, we got an abundance of riches in terms of our portfolio. We have the ability to lean in, depending on how we see that macro environment continue to evolve. But taxes, while part of the discussion aren't the driving factor.
Okay. My --
Doug, you giving me way too much credit for financial engineering that were capital allocation.
There's a big NOL that is getting monetized now. So, we like that. So, fellas, I apologize, I have to touch on the buyback because, obviously, it's a new tool in your portfolio. But I want to frame it like this, Tom, because -- and I mean this with a great respect to what you've put together here. You designed the combined company as a low data company. And it has, as a consequence, materially underperformed your E&P peers through the commodity recovery since the deal closed.
In fact, I was looking at it this morning, your share price is almost exactly in line with ExxonMobil, believe it or not, over the last year or two. So, my question is, when you think about this higher commodity environment, and the relative underperformance versus your peer group, how does that change or shift your view of what the buyback can do to help close the gap versus the variable distribution, excuse me, which is obviously somewhat transitory?
Scott, I'm going to let you handle that one.
Sure. Yes, Doug, again, I hear your point. Exactly that was part of our decision. That was part of our presentation to the Board in February when we got the $1.25 billion authorization approved. We were looking at that relative performance. And as I said in my comments, we look at that relative performance, we look at the intrinsic value, tie those -- both of those to where the commodity is and kind of look at where we think we should be trading.
Now, we're not going to tell you where we think that is. But that all plays into it. We have made the commitment on the other side to return at least 50% in the form of cash through the base plus variable. And you know us, both legacy companies as a combined company, we're not going to go back on our word. But a little of going -- at the end of the day, we stopped at 50% in the quarter, the first quarter because of the fact that it will be paid in the second quarter and used that increment to lean in on the buyback.
Now, keep in mind, the buyback I feel we were very successful, but we only had March to do that. We put a 10b-5 in place and you have to put parameters in and let it run. You can't touch it. So, we will continue to lean in on this. We hear your point, but we still think the all the above approach is the right way to do it. And over time, I believe, and I think the team believes that we will close that gap eventually.
Thanks fellas. I appreciate the long answer.
Thanks Doug.
Your next question is from Neal Dingmann of Truist Securities. Please go ahead, your line is open.
Good morning. Maybe, Tom, my first question for you -- specifically on Marcellus. [Technical Difficulty] opportunity you all see with the Upper Marcellus [Technical Difficulty] success on the uplift?
You came in pretty scratchy there. But your question is on the upper Marcellus and inventory. As we have previously discussed, we're currently flowing back some Upper Marcellus tests. We're very encouraged by what we see. I haven't changed my thinking on the Upper Marcellus. I really like the Upper Marcellus. I think it's going to surprise to the upside. We have a very broad, deep inventory there.
But it's an interesting problem. It is different than the Lower Marcellus and may involve some different completion techniques. It's part of the what the team is discussing today. It's a big fix section and not bound as much as the Lower Marcellus. And we're going to be experimenting to optimize it. But it's a tremendous source rock, and I think it's going to be everything that we've hoped it would be. I mean we really do have very good data that backstops our optimism on there from Marcellus.
Your next question is from David Deckelbaum of Cowen. Please go ahead. Your line is open.
Thanks for taking the questions Tom and Scott.
Hi David.
Tom, I wanted -- hey there. I wanted to ask you, Tom, just to elaborate a little bit more on the embarrassment of riches problem. I know Doug asked a good question around allocation of capital. And I guess, from the investment side or the analyst side, when you lay out the context of being constructive on natural gas macro, should we think about capital going into areas like the Marcellus or Anadarko as really an allocation or reallocation and potentially saving capital from the Permian, or should we think that we would see growth capital in those areas first?
Well, those are my only two choices.
I guess you could create a third, yeah.
Okay. All right. We really do look at it from a zero start. I mean there's no capital in our program that has a permanent placeholder. We look at asset performance; we look at particular projects and what they can deliver. We look at market conditions. And if we think there are any overprints on marketing, that can be basis, can be restraints along those lines. But we are extremely constructive on oil and natural gas.
Now that said, in the midst of all this optimistic talk and I'm probably the most optimistic on the call, I want to remind everybody that we haven't repealed the commodity cycles. And it's not like we said to ourselves, wow, we don't have to worry ever again about prices cycling downward.
We probably -- as I said in my opening remarks, the fundamentals look fantastic. But look, nobody should follow me around on this topic. I'm not aware of too many experts out there that have consistently gotten it right. So the diversity of our assets, the diversity of our exposure to the commodity, and our ability to pivot capital is really important to us. We don't want to put all of our eggs in one basket regardless whether that basket sits in Midland or Pittsburgh. And the fact that we have absolutely stellar returns, quick payouts and such great operating teams in really three different basins is everything that was our rationale for building Coterra. And now more than ever, we are convinced that Coterra is fit for our times.
I appreciate the comments there, Tom. Maybe just as a quick follow-up, just when we think about specifically to the Marcellus, your gas price exposure by index, is there a meaningful shift in composition that we would expect in '23 versus, say, '22 whether it's on like the fixed price or NYMEX-linked pricing or any other areas that we might be considering or not considering where your pricing mechanisms might be improving next year?
Yes, David, this is Blake. I'll take that one. I wouldn't expect any material changes. We have a lot of great long-term deals. We're diversified to a lot of good indexes that give us lots of different pricing power, and we expect that to continue. So, I wouldn't expect anything.
Thanks Blake and thanks guys.
Your next question is from Leo Mariani of KeyBanc. Please go ahead. Your line is open.
Hey guys, wanted to follow up with sort of a big picture question here. You obviously talked about Coterra being well positioned for LNG exports and trying to find the right deal out there. But just realistically, do you guys think there can be any material expansion of US LNG export capacity in say, 2023, or do you think that whatever does kind of occur out there is kind of more of a sort of mid-decade potential expansion? And then just additionally, do you think that there will be available deals for US producers to get more international pricing in some of these deals are going to be more Henry Hub link type deals?
Yes, Leo, this is Blake. I'll take a crack at that. I mean, in general, most of the new capacity that's coming on right away was spoken four years ago. And new capacity coming is all mid-decade and that's what's being shopped in the market. I think there's – competition is a great thing. And if there's a lot of demand overseas and there's more LNG projects in the US, that's going to drive more competition in the deals for producers. And so, we're a big supporter of LNG. We would love to see a bunch of new LNG terminals pop up along the East Coast. So, if we can figure that one out, there's plenty of opportunities but time will tell.
Yes. Okay. Helpful. And just wanted to follow up on cash taxes as well. You all are predicting kind of a 20% to 30% basically deferred tax rate here in 2022. At these kind of prices, do you think we're maybe looking closer to the 20%? And do you think that, that cash tax rate goes up next year if prices stay strong, maybe you'll burn through a lot of incremental NOLs or something?
Yes, Leo, this is Scott. The answer to both of them is yes. Yes, closer to the 20%, as you see the impact on commodity prices this year being way more positive moving it closer to the 20%. And if those stay in place, you'll have the same effect next year, maybe moving even below 20%.
Okay. Thanks guys.
We have completed the allotted time for questions. I will now turn the call over to Tom Jorden for closing remarks.
Thank you, Cheryl. I just want to thank everybody for joining us this morning. We look forward to continuing to deliver great results. As you know, we like talking about results, and we're going to be working hard to consistently generate them, which is the theme that form Coterra. I want to wish everybody the best, and thank you for your support, and thank you for a lot of very good questions this morning. Thanks, everybody.
This concludes today's conference call. Thank you for your participation. You may now disconnect.