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 First Quarter 2022 conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, again, press star one. 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 this 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 reconciliations to the most directly comparable GAAP financial measures were provided in yesterday afternoon's earnings release, which can be found on our website. Following the 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, Katerina, and thank you to all who are 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 in 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 7.6 million shares totaling $184 million. Taken 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, oil field services, and trucking are all moving upward. Lead times for ordering tubulars, compressors, electrical equipment, production equipment, and line pipe are, in many instances, 12-14 months from order to delivery. Premier drilling rigs and premier completion crews are in short supply. Overall, we are seeing inflation moving towards 15%-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-$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 frack crew, which arrives 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 outlooks. For many years, any conversations on global oil supply ultimately pivoted to a conversation on 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 welcomed 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 U.S. LNG exports a vital component to world energy supply. Energy security has returned as a top concern, and U.S. natural gas has a leading role to play in global energy security and U.S. geopolitical influence. We have seen solid support in natural gas prices, natural gas optimism, and a serious discussion on the long-term role of U.S. natural gas in the world arena. Coterra is well-positioned to contribute to this critical need for U.S. natural gas and U.S. LNG exports. Finally, a few words on the E&P sector's ability and willingness to respond to increasing demand. The U.S. 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 overinvestment. 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 sentiment 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 a revised approach to disciplined investing. Now, we find ourselves in a global energy crisis.
Starting last summer, natural gas prices in 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 U.S. E&P sector to respond with increased U.S. 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 U.S. 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. 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 twelve-month EBITDAX leverage ratio stands at 0.41x 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 $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%+ 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 605-625 MBOE per day, with natural gas and oil volume guidance set at 2.725-2.775 BCF per day and 82-84 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 GP&T and LOE, we expect to remain within our original unit cost guidance. G&A expense for the quarter was $1.48 per MBOE, which included $0.54 per BOE of 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.
To ask a question, please press star one. Please limit yourself to one question and one follow-up. The first question is from Neil Mehta of Goldman Sachs. Please go ahead. Your line is open.
Yeah, thanks, and congrats on the continued capital return. Tom, I wanted 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? Then tie it into your views on Waha as well. 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. You know, we are, as you, I hope, are not surprised, very constructive on natural gas. Now, of course, you know, both commodities are backwardated, if you look at the strip. We've seen support for natural gas well above what we've seen in recent years. You know, we see that as a response to fundamentals. You know, 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. We are very constructive on natural gas and really pleased to see the support it's achieved. Now, you know, you asked me if I worry about Waha, you know, Neil, I worry about everything.
It's what I do. We're not panicked. We think that the market will adjust, and that a lot of these fears that are currently in the air are going to prove to be overblown. To that, I'm gonna 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%-10% of our total Coterra gas portfolio. We're evaluating all the 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.
We're not against adding more FT if it makes sense, but we're gonna 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. Stay tuned.
All right, 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-$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 blowing off the top ends. Thank you.
No. That. Yeah, 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, you know, we heard from a lot of your peers about the LNG opportunity and the long-term ways to participate in international pricing. Could you talk about what you are seeing out there? You know, you have access to multiple markets. Are there any risks that you are seeing on the LNG market?
Again, Nitin, I'm gonna turn this over to Blake, but, you know, we have studied the LNG markets hard. 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. 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, you know, Coterra moves 350 million cubic feet a day every day through Cove Point on a long-term LNG deal. We absolutely have the wherewithal to do these long-term commitments and experience with LNG. When we look at our assets, we've got three basins with multiple decades of high-quality inventory. 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. 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.
We're wrangling all that right now and 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. We haven't found one yet, but we're gonna keep hammering away at it.
Great. Appreciate the color, guys. Tom, congrats on, you know, the first successful quarter of the buyback. You entered the second quarter with a 10b5-1. It sounds like you are still leaning into that buyback program. If I could, how do you see the buyback program evolving? You know, 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 wanna understand how this evolves from here.
Well, of course, we and Nitin, we filed that 10b5-1 before we went into quiet period, and we'll talk at, as Scott has said, at our next quarter release on what action it spurred. You know, we're. I'll say this, Nitin, we are constantly having to rethink mid-cycle pricing. You know, classically, we entered the year with $55 and $2.75 being our definition of mid-cycle pricing. For a certain period of last fall, that sounded fairly aggressive to us. Now when you look at that today, you would say, "Boy, that's 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. You know, with that, you know, Scott, why don't you comment on this?
Yeah, 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. We will continue. We're not gonna be granular and kind of explain where we put the price points in the 10b5-1 plan. We were effective, and we did execute on some of that, but we saw the prices, what we've seen in the prices run up. The outcome of the first quarter highlights exactly where we wanna be, and that is, you know, when the average of what we bought in that we've announced is $24.16. We got a price with, you know, pushing $29, pushing $30 this morning on the announcement.
Again, we're not just gonna chase the thing up, but when we find opportunities and look at the relative valuation and the intrinsic valuation, 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. I agree with Tom's point wholeheartedly. We've got to kind of reassess what that mid-cycle price is right now.
Yeah. Nitin, I'll just wrap it up. 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 a cyclic market in oil and natural gas. I mean, it's all where we wanna be. That said, when we launch the buyback, we wanna pursue it aggressively, but we just feel like it ought to be tempered at some mid-cycle pricing. You know, the answer to your question is more about what do we think mid-cycle ought to be rather than, you know, 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. You know, 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. Now suddenly it looks like we have some ground support. I think we're all watching and rethinking how we ought to view what mid-cycle means. That's kind of where we are. We are extremely bullish on Coterra.
Great. Thanks, Tom. Yeah, it is good to be bullish and cheerlead people on 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. You know, we are hearing about some challenges on the frack sand side in the Permian, but I just wondered if you could maybe run through, you know, your management of the supply chain and what gives you confidence on being able to execute in this kind of environment?
Well, I'll tee it up, and then I'm gonna let Blake comment. We always have built relationships, Arun. I think you know that. You know, we've had many times when relationships cost us a little and many times when they benefit. We are long-term planners. We're long-term thinkers. You know, we like to have relationships through thick and thin. So, you know, we don't wake up every morning and panic. We've got some really good partners out there in the oilfield service space. Blake, why don't you comment on supply chain?
Yeah. Arun, you know, specifically starting with sand, we saw early in the year things, especially in the Permian, were getting pretty hectic out there, in the sand market. We actually went out and purchased all our sand for the whole Permian program for the year. In Marcellus we're under contract for our sand for the year. 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. We still have exposure, you know, 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 to date in our projections, and that's what's reflected.
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% year-over-year in number of wells. 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. 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.
You know, Arun, if I could just follow on with that. You know, Blake mentioned two elements. One is cost inflation, but the other is just supply chain bottlenecks. You know, 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, you know, we did pre-buy our sand, and we are pre-ordering a lot of stuff for 2023. You know, it's just remarkable the extension in lead time between order and delivery. You know, we're on top of it as we look into 2023 and beyond.
You know, we're doing multi-year planning, and we got a good head start on this.
Great. Just my follow-up, Tom, you know, you guys have always had a very dynamic kind of capital allocation program. I was wondering, you know, a lot of the program as we think about today was based on a much different pricing environment. You know, 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, so in the or upper single digits or so in the Anadarko Basin. I was wondering how you think about adjusting the development plan in a much higher price environment where, you know, there may be some inventory that in a, you know, call it a $3 case that you didn't get to, but maybe in a $5 that you.
that may make sense to you know to take advantage of. I was wondering if you could give us your philosophical thoughts on that question.
Well, in some sense I'm gonna answer it describing an embarrassment of 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 other issues. We do rank our inventory, excuse me, and we're certainly gonna fund from the best returns down. You know, a lot of that, excuse me, lower inventory stuff is still gonna be lower in the ranking. Marcellus, [Anadarko], 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. That's something, Arun, 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.
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 was that 2022 would be back half weighted in both the Permian and the Marcellus. 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. Just wondering if you could talk about maybe any updated thoughts on how you're viewing oil during the second half of the year. Then on the gas side, maybe it's a little more straightforward because, you know, 2Q's 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. We do see, you know, 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, you know, that's just around project timing. It's around pad size. There's nothing, you know, organically problematic to it. As we get into longer laterals and larger pads, this is just nature of the beast. Scott?
Yeah. Yeah, sure. What I would add is, you know, exactly what Tom said. It's just the timing, it's the cadence. You know, 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. 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, you know, again, solidify that second half ramp that we are planning for.
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. 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? Is it really more about the absolute return rather than the percentage every quarter? Thank you.
Yeah, I wish I could tell you we had some formula or machine learning algorithm to do this, but it's, you know. It's a judgment call. This quarter we were pleased to have a combined ordinary and variable dividend that exceeded what we paid last quarter. We also took into consideration the progress we've made in our buyback and the progress that we hope to make on our buyback. You know, we did want to keep a little dry powder in terms of cash. You know, Jeanine, it's a judgment call and, you know, 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 you know, 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. 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 and as well as with other folks just, you know, 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. We were recently on a non-deal roadshow and engaged with a lot of our owners, and those were really good conversations. I will say that, you know, I hope you glean from my remarks that it's not just one string you can pull here. You know, 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. You know, we're not gonna estrange more investors here. I absolutely gonna 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 producer is ready to do our part. You know, 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, U.S. onshore and offshore to return to global dominance in terms of an energy leader. We're ceding geopolitical influence in ways that are unnecessary, and we need leadership. We also need, you know, people to just come together and solve the problem, and we're ready to do our part. I think our owners are too. As I say, we're not gonna screw my owners. We're gonna certainly be in constant communication with our owners.
We're not talking about returning to the, you know, I think irresponsible capital days of yore. A lot has changed in our business. One is a lot of our projects pay out in a very short amount of time. You know, we're not talking about years to pay out, we're talking about months on some of these projects. That's gotta change your thinking on risk of capital allocation. We just need some very thoughtful people helping solve this problem. Thank you for that question, Holly.
Yeah. No, those are some good points. Scott, maybe asking you one that hasn't been asked yet. There is an $8 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. I guess my question would be, can this price be ignored on the natural gas side for hedges?
The simple answer is no, it cannot be ignored. You know, 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 at 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 wanna see if you could give any more color on that. Anything you can say about the two wells you've completed, what the returns look like, and what's 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. Historically, we've drilled third Bone Spring sand and a second Bone Spring sand. It's a shale that lies in that Bone Spring section. It is a shale. It's a sand up in Eddy County, New Mexico, and then it goes into a shale in Culberson, Reeves, and Loving County. We at Coterra, legacy Cimarex, drilled our first test in it in late 2019, brought it online in December of that year and had a very nice result.
We've tested it a number of places and have had outstanding success. We really brought or bring 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, you know, I think adding five years of top-tier inventory would not be a stretch, just this landing zone alone. You know, it's not. It grades in quality, but it's really good. You know, second tier is really good here. We've been excited about it for a while.
This is the first time we've 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.
Mm-hmm.
Wanted to ask too on your, you've pushed the number of wells per pad in the Permian to more than 8 in the last few years from, I think you were just a little over 3 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 with pushing that number higher?
I am very comfortable with pushing that number higher. Now, you know, that's how I view it, Mike. I'm gonna be, you know, clear with you as you always expect me to be. I view it completely through a lens of what's the best business decision. I know from time to time that it's very difficult for the external world to understand lumpiness in production and a production cadence that's not just smooth and consistently up to the right. That, you know, I wish that were the way the world worked, 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 emissions 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. You know, 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. You know, the 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 gonna make good business decisions. I'd rather explain a good business decision than react to a market that doesn't understand and so make a poor one.
That, that's the way we think about it.
Appreciate that, Tom. Thanks.
Your next question is from Matt Portillo of TPH. Please go ahead. Your line is open.
Good morning, all. Thanks for the questions.
Hi, Matt.
Just one quick one for me, Tom. I know the team's 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 gonna 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. You know, 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. There's just such a great spirit of technical curiosity that's shared between our Anadarko, our Permian, and our Marcellus business unit. From that collaboration, everybody gets better. Blake, why don't you just comment on that?
Yeah, just to echo Tom, you know, you take the Permian, the Anadarko, and the Marcellus, and they all have their very unique challenges. 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. That's bringing some really interesting discussions, some really interesting solutions that we would never see just looking over the lease line. You know, 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 a new way. Vice versa, the Marcellus team is challenging the Permian team and the Anadarko team. It'll be exciting to see where it goes.
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, you know, 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, you know, $1 billion or so of free cash flow to distribute. Just wanna 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.
Yeah, 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. You know, I appreciate the fact that you did bring up debt. You know, is there a wedge of that that goes to debt repayment? Again, we have the maturities in 2024, $1.3 billion. Again, we're not leaning in hard on that, but that's all gonna be part of the equation internal and in the boardroom as to what we do. Obviously, the Fed is gonna meet tomorrow, and we'll see what interest rates do in response to that. 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's in play. 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, you know, 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. I appreciate the
Hi, Doug.
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. You know, 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, you know, with the opportunities that might reset for you within the portfolio?
Yeah, Doug, we're looking at that now. We're getting a head start on 2023. Yes, I would not be surprised to see us pivot capital into the Marcellus. It's a remarkable asset with remarkable returns. You know, 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. Boy, they're taking me at 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. 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 gonna make the best business decision. 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. Taxes, while part of the discussion, aren't the driving factor.
Okay. Understood.
Doug, you're giving me way too much credit for financial engineering if that were a capital allocation.
There's a big NOL that, you know, is getting monetized now, so we like that. Fellas, I apologize. I have to touch on the buyback because obviously it's a new tool in your portfolio. I want to frame it like this, Tom, because, and I mean this, you know, with the greatest of respect to what you've put together here. You designed the combined company as a low beta 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.
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 gonna let you handle that one.
Sure. Yeah, Doug, you know, 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. As I said in my comments, you know, we look at that relative performance, we look at the intrinsic value, tie both of those to where the commodity is and kind of look at where we think we should be trading. Now, we're not gonna 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.
Again, you know us from both legacy companies and as a combined company, we're not gonna go back on our word. But you see a little, you know, inkling of going at the end of the day, we stopped at 50% in the second quarter, or in the first quarter because of the fact that it'll be paid in the second quarter and use that increment to lean in on the buyback. Now, keep in mind, the buyback, I feel we were very successful at, but we only had March to do that. We put a 10b5-1 in place, and you know you have to put parameters in and let it run. You can't touch it. 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. 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.
More than anything, Tom, my first question is for you. On the specific Marcellus, I'm just wondering, could you speak to the potential opportunities you all see with the upper Marcellus in light of the unification internally when you think about your total deployed today and the downside that is based on success around that re-op?
Yeah. Neil, you came in pretty scratchy there, but you know, your question's on the Upper Marcellus and inventory. You know, we-
Yes, sir.
As we have previously discussed, we're currently flowing back some upper Marcellus tests. We're very encouraged by what we see. You know, 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. You know, it's an interesting problem, and it's different than the lower Marcellus and may involve some different completion techniques. It's part of what the team is discussing today. It's a big thick section and not water-bound as much as the lower Marcellus. You know, we're gonna 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 the Upper 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. Tom, I,
Hi, David.
Hey there.
I wanted to ask you, Tom, just to elaborate a little bit more on the embarrassment of riches problem. You know, I know Doug asked a good question around allocation of capital. 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 thieving capital from the Permian? Or should we think that we would see growth capital in those areas first?
Well, are those my only two choices?
I guess you could create a third. Yeah.
Okay. All right. You know, 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, and that can be basis, can be restraints along those lines. You know, we are extremely constructive on oil and natural gas. Now, that said, you know, in the midst of all this optimistic talk, and I'm probably the most optimistic on the call, I wanna remind everybody that we haven't repealed the commodity cycles.
You know, it's not like we say to ourselves, "Wow, we don't have to worry ever again about prices cycling downward." We probably, you know, 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. The diversity of our assets, the diversity of our exposure to 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 of where that basket sits in Midland or Pittsburgh.
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. 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 2023 versus, say, 2022, 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?
Yeah, David, this is Blake. I'll take that one. I wouldn't expect any material changes. You know, 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. 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. Just, you know, realistically, do you guys think there can be any material expansion of U.S. LNG export capacity in, say, 2023? Or do you think that, you know, whatever does kind of occur out there is kind of more of a sort of mid-decade, you know, potential expansion? Just additionally, do you think that there will be available deals for U.S. producers to get more international pricing in some of these deals, or are they gonna be more Henry Hub linked type deals?
Yeah, 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 for years ago. New capacity coming is all mid-decade, and that's what's being shopped in the market. You know, I think there's competition. Competition's a great thing, and if there's a lot of demand overseas, and there's more LNG projects in the U.S., that's gonna drive more competition in the deals for producers. We're a big supporter of LNG. We would love to see a bunch of new LNG terminals pop up along the East Coast. If we can figure that one out, there's plenty of opportunities, but time will tell.
Yep. Okay. No, helpful. I just wanted to follow up on cash taxes as well. So y'all are predicting kind of a 20%-30%, you know, basically, you know, deferred tax rate here in 2022. You know, at these kind of prices, do you think we're maybe looking closer to the 20%? And do you think that cash tax rate goes up next year if prices stay strong? Maybe you'll burn through a lot of, you know, incremental in the wells or something.
Yeah, Leo, this is Scott. The answer to both of them is yep. 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%. 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 wanna 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 gonna be working hard to consistently generate them, which is the theme that formed Coterra. Wanna 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.