Alpha Metallurgical Resources Inc (CTRA) — Q1 2022 Transcript

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 an updated investor presentation, which can be found on the company's website. Today's prepared remarks will include a 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 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 executed 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 back 7.6 million shares totaling $184 million. 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 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 have returned as an important 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, makes natural gas and US LNG exports a vital component of 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 global 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 due to a 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 stance 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 the 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 legislators 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 drilling and completions 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 $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 over 50% of free cash flow via the base plus common dividend, while 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 2.775 Bcf per day and 82 to 84 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 general and administrative expenses and lease operating expenses, we expect to remain within our original unit cost guidance. General and administrative 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.

Yes, thanks. Congratulations on the continued capital return. Tom, I would like your perspective on the current gas market. The front month is near $8, and the curve has also strengthened significantly. Can you discuss whether you believe the fundamentals are supporting the current price? Additionally, how do you view Waha? Are you concerned about any potential disconnect there? What strategies are you implementing to address this risk?

Thank you for the question, Neil. I'll start by addressing the natural gas market and then let Blake provide insights on Waha. We have a positive outlook on natural gas. Although both commodities show backwardation when examining the strip, natural gas has seen support levels significantly higher than in recent years. This trend reflects fundamental factors at play. As I mentioned previously, there is an increasing awareness of the importance of natural gas, and the market is reacting to this. So, we remain optimistic about natural gas and are encouraged by the support it has garnered. As for your concern about Waha, I tend to worry about various aspects of the market, but I am not alarmed. We believe the market will adapt, and many current anxieties are likely exaggerated. Now, I will turn it over to Blake to discuss Waha further.

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 firm transport if it makes sense, but we're going to view it through a long-term lens. 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, the 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, from what we said, yes.

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 in 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, adaptive, and 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, 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 make 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. So supply is not an issue for us. The challenge is just economics. It's expensive to get to the coast. There are 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. That's primarily shown through in the deals that are being offered to the producers. So we're assessing 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.

We filed that 10b-5 before entering a quiet period. We'll discuss the actions it prompted at our next quarterly release. I want to emphasize that we are continuously reevaluating mid-cycle pricing. At the start of the year, we defined mid-cycle pricing as $55 and $75, which seemed quite ambitious last fall. However, considering the current situation, that appears to be a more cautious perspective on mid-cycle pricing. We prefer not to speculate publicly on the value of a Coterra share. Scott, would you like to add your thoughts on this?

Yes, of course, Tom. As we mentioned earlier regarding the history of legacy companies, this is just another method for returning capital to our shareholders. We will keep this up. We're not going to provide specific details about the price points in the 10b-5 plan. We have been effective and executed some of it, but we've noticed the recent increase in prices. The outcome from the first quarter shows exactly where we aim to be; the average price of our purchases, which we have announced, is $24.16, and we're seeing prices around $29 to $30 this morning following the announcement. Once again, we're not going to chase prices upward, but as we identify opportunities and assess relative and intrinsic valuations, this will remain part of our return strategy. During certain market cycles, we will rely on it more than in others. I completely agree with Tom's point; we need to reassess what the mid-cycle price is at the moment.

We have a very positive outlook on Coterra, which I hope comes as no surprise. Our asset performance looks strong, our inventory is solid, and we are well-positioned in the cyclical market for oil and natural gas. We launched the buyback with the intent to pursue it vigorously, but we believe it should be moderated at certain mid-cycle prices. The focus is on determining what we consider to be mid-cycle pricing rather than expressing bullishness on Coterra at the current share price. I mentioned our optimism about commodities, supported by supply-demand fundamentals, which I haven't been able to say for a long time. Recent mid-cycle pricing has been more of an estimation in a highly fluctuating commodity market, but it seems we now have some stability. We're all reassessing our understanding of mid-cycle pricing at this point. Nevertheless, we remain very optimistic about Coterra.

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 able to execute in this kind of environment?

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. We are long-term planners and thinkers. We like to have relationships through thick and thin. 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, were getting pretty hectic out there in the sand market. 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 sand 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, and 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. 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. So supply chain is a challenge, inflation is a challenge, but our operations 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. Cost inflation is out there and hard to fully predict. However, we can do something about supply chain bottlenecks by careful planning, by ordering ahead, and ensuring that we have conversations with our partners to let them plan as well. Blake said we did pre-buy our sand, and we are preordering a lot of stuff for 2023. It's remarkable the extension in lead time between order and delivery. We are on top of it as we look into 2023 and beyond. We are doing multi-year planning, and we have 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. 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 $3 case, may not get developed but in a $5 scenario, may make sense to take advantage of. So I was wondering if you could give us your philosophical thoughts on that question.

In some sense, I'm going to answer it by describing barriers for the riches. One of the great things about having a deep inventory is we can really make decisions around capital returns and not worry about other issues. 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. We are going to be aggressive in just waking up every day and putting capital where it needs to flow. That's something you’ve heard from us for a long, long time.

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 into the detail here. But I think the expectation with that 22% would be back half weighted in both the Permian and the Marcellus. When looking at the 2Q guide, it implies flat sequential oil production at the midpoint, which is also flat versus the midpoint of the full year guide. So just wondering if you could talk about 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 Scott to comment. 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 and 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. 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, there are very few rigs running and very few completion crews running. So it's just 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? Is it really more about the absolute return rather than the percentage every quarter? Thank you.

Well, I wish I could tell you we had some formula or machine learning algorithm to do this, but it's a judgment call. 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 wanted 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 that I missed there?

No, I think you covered it perfectly, Tom. The key issue 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. That’s why we landed it at 50% this time because, as Tom indicated, we exceeded what we did last time at the 50% level.

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. 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. 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'm 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 are ready to do our part. 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 come together and solve the problem, and we're ready to do our part. I think our owners are too. We're not going to stray from our owners. We're going to be in constant communication with our owners. We're not talking about returning to the irresponsible capital days of work; a lot has changed in our business. One is that 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. That will 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. 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 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. We will continue, as we have in the past, with our hedge committee. We were active again recently even this week, and we will continue to lean in and monitor the market.

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?

Mike, I'll take that question. This isn't actually a new shale in the basin; it's one that several other operators are currently drilling in the Bone Spring section. Historically, we've drilled in the second and third Bone Spring sands, and this shale is located within that section. At Coterra, our previous company Cimarex, we drilled our first test in late 2019 and brought it online in December of that year, achieving very positive results. We've tested in various locations and have seen great success. We are currently developing a project that consists of four wells per section. We estimate this landing zone can support around four to six wells per section, significantly enhancing our top-tier inventory, potentially adding around five years of it from this landing zone alone. While the quality varies, it is generally very good, with the second tier also showing strong potential. We have been enthusiastic about this for some time, and this is the first time we are discussing it publicly. We have results to share, and we are eager to incorporate this into our strategy for generating strong returns on capital.

Thank you for that update. I'm encouraged by what I heard. I wanted to ask about your recent increase in the number of wells per pad in the Permian, which has risen from just over three in 2018 to more than eight now to enhance efficiencies. Typically, such an increase leads to longer delays between capital investment and cash flow. How do you perceive that trade-off in the current inflationary climate? Do you believe you are approaching the maximum number of wells per pad, or are you open to increasing that number further?

I am very comfortable with pushing that number higher. Now, yes, how I view it, Mike. I’m going to be clear with you as you always expect me to be. I view it completely through a lens of what's the best business decision. From time to time, it’s very difficult for the external world to understand the lumpiness in production and the production cadence; that’s not just smooth and consistently up to the right. I wish that were the way the world works, but it's not the way it operates. These larger pads 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 cut down the number of contributors of emissions, centralize them, and really deliver the cleanest barrel in the world. 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. It's not always the best business decision because it also extends your lead time from first spud to first production. But the answer to your question is, how do I think about it? It's the absolute best business decision. I’d rather explain a good business decision than react to a market that doesn't understand and make a poor one. So that’s the way we think about it.

Good morning, all. Thanks for the question.

Hi, Matt.

Just 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 could potentially change your views on the capital efficiency for that asset moving forward?

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 reviewing a lot of the machine learning that we've pioneered. Machine learning has become a very important part of our completion design and that's something I 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 units. 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 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 brings some really interesting discussions and solutions that we would never see just looking over the lease line. Right now, in the Marcellus, there's lots of work going on to run new models and look at things in a new way. Conversely, the Marcellus team is challenging the Permian team and the Anadarko team. It'll be exciting to see where it goes.

Yes, Matt, I think you're considering the base and the variable aspects. We also have buybacks, and I appreciate you mentioning debt. Is any portion of that allocated for debt repayment? We have $1.3 billion in maturities coming up in 2024. While we’re not aggressively pursuing that, it factors into our internal discussions and boardroom considerations. The Fed is meeting tomorrow, and we’ll see how interest rates respond. Additionally, we need to consider the refinancing risk that may emerge in 24 months. We are monitoring that while taking advantage of the current excess free cash flow. We remain committed to returning at least 50% of the $4.5 billion to shareholders if that amount holds steady throughout the year. Clearly, commodity prices can fluctuate, but as Tom mentioned, we are observing a shift in the system that suggests very positive prices for an extended period.

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. 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 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. 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 create a difficult job for capital allocation. They are taking me at my word on that; we've got some really good options.

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. As we've mentioned, we got an abundance of riches in terms of our portfolio. We can lean in depending on how we see the macro environment continue to evolve. But taxes, while part of the discussion, aren't the driving factor.

Okay. My focus is on capital allocation. They are taking me at my word on that; we've got some really good options. 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. As we've mentioned, we have an abundance of riches in terms of our portfolio. We can lean in depending on how we see the macro environment continue to evolve. But taxes, while part of the discussion, aren't the driving factor. There's a significant net operating loss that is currently being monetized, which is encouraging. I need to address the buyback since it is a new strategy for you. I want to present this in a respectful manner, Tom, considering the foundation you have established. You structured the combined company to operate as a low data entity. As a result, it has significantly lagged behind your exploration and production peers during the commodity market recovery since the merger. Interestingly, I noticed this morning that your share price has closely tracked ExxonMobil's over the past couple of years. My question is, in light of the current high commodity prices and your relative underperformance compared to peers, how does this influence your perspective on the potential benefits of the buyback to help bridge the gap compared to the variable distribution, which is somewhat temporary?

Scott, I'm going to let you handle that one.

Sure. Yes, Doug, again, I hear your point. 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, we look at that relative performance, we look at the intrinsic value, tie those both of those into where the commodity is and look at where we think we should be trading. Now we're not going to tell you where we think that is. But that plays into it. We have made the commitment on the other side to return at least 50% in cash through the base plus variable. Both legacy companies as a combined company, we're not going to go back on our word. A little going – at the end of the day, we stopped at 50% in the quarter, the first quarter because it will be paid in the second quarter and used that increment to lean in on the buyback. Keep in mind, the buyback has been 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. We will continue to lean in on this. We hear your point, but we still think the all-of-the-above approach is the right way to go. Over time, both the team and I believe that we will close that gap eventually.

Good morning. Tom, could you please provide more details about the opportunities you see with the Upper Marcellus?

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. It's an interesting problem. It is different than the Lower Marcellus and may involve some different completion techniques. It's part of the discussions the team is having today. It’s a big fix section and not bound as much as the Lower Marcellus. We will be experimenting to optimize it. It's a tremendous source rock, and I think it's going to be everything that we've hoped it would be. We have very good data that backs up our optimism on there from Marcellus.

Thanks for taking the questions, Tom and Scott.

Hi, David.

Tom, I wanted to ask you just to elaborate a little bit more on the embarrassment of riches problem. I know Doug asked a good question around allocation of capital. 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? Okay. All right. We really do look at it from a zero start. 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. If we think there are any overprints on marketing, that can be basis restraints along those lines. But we are extremely constructive on oil and natural gas. That said, in the midst of all this optimistic talk, I'm probably the most optimistic on the call; I want to remind everybody that we haven't repealed the commodity cycles. It's not like we're saying to ourselves, wow, we don't have to worry ever again about prices cycling downward. As I said in my opening remarks, the fundamentals look fantastic. Nobody should follow me around on this topic. I'm not aware of too many experts out there who have consistently gotten it right. The diversity of our assets, the diversity of our exposure to the commodity, and our ability to pivot capital is really important. We don't want to put all of our eggs in one basket regardless of whether that basket sits in Midland or Pittsburgh. The fact that we have stellar returns, quick payouts, and great operating teams in 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 the Marcellus, your gas price exposure by index, is there a meaningful shift in composition that we would expect in '23 versus, say, '22 and whether it's on like the fixed price or NYMEX-linked pricing or 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 wouldn't expect any material changes. We have a lot of great long-term deals. We're diversified to a lot of good indices that give us lots of different pricing power, and we expect that to continue. So I wouldn't expect anything.

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 mid-decade potential expansion? Additionally, do you think there will be available deals for US producers to get more international pricing, or will some of these deals be more Henry Hub linked?

Yes, Leo, this is Blake. I'll take a crack at that. In general, most of the new capacity that's coming on right away was spoken for four years ago. New capacity coming is all mid-decade and that's what's being shopped in the market. I think competition is a great thing. If there's a lot of demand overseas and more LNG projects in the US, that will drive more competition in the deals for producers. We're big supporters of LNG and we'd love to see some new LNG terminals pop up along the East Coast. If we can figure that one out, plenty of opportunities, but time will tell.

Yes, Leo, this is Scott. The answer to both is 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%.

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 the very good questions this morning. Thanks, everybody.