Thank you for standing by. At this time, I would like to welcome everyone to the Coterra Energy Fourth Quarter 2022 earnings 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 1 on your telephone keypad. If you would like to withdraw your question, again, press star 1. Thank you. Dan Guffey, Vice President, Finance, Planning, Analysis and Investor Relations, you may begin your conference. Thank you. Good morning. Thank you for joining Coterra Energy's fourth quarter 2022 earnings conference call. Today's prepared remarks will include an overview from Tom Jorden, Chairman, CEO, and President, and Scott Schroeder, Executive Vice President and CFO. Also on the call, we have Blake Sirgo and Todd Roemer. Following our prepared remarks, we will take your questions during our Q&A session. 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 our earnings release and updated investor presentation, both of which can be found on our website. With that, I'll turn the call over to Tom. Thank you, Dan, and welcome to all of you who've joined us for our fourth quarter conference call. We're looking forward to a fruitful discussion on Coterra performance, outlook for 2023, 3-year outlook, and our tune-up on our return of capital approach. We had an excellent fourth quarter and full year in 2022, driven by superior asset performance, good execution, and some commodity price windage. We finished the fourth quarter above the high end of our guidance on both oil and natural gas. This was made possible by the efforts we undertook during the year on weatherization. We experienced little downtime during the December winter storm events in the Permian, Anadarko, and the Marcellus. This took careful planning, smart engineering, great field coordination and perseverance, and a lot of grit on the part of our operational staff in all three regions. The lack of significant downtime was also helped by collaboration between our Permian, Anadarko, and Marcellus business units. We brought our teams together earlier in the fall to share experiences and best practices on weatherization. It paid off. Kudos to our teams who kept us online and flowing during these challenging weather events. We also generated excellent financial results during the quarter and full year. For the full year 2022, we generated almost $4 billion in free cash flow. We returned almost $2 billion in cash to our shareholders through the dividends, bought back $1.25 billion of Coterra stock, and retired $874 million in long-term debt. We achieved almost all of our annual operational goals, including a continuation of our multi-year effort towards emission reductions. Coterra maintains one of the lowest emission intensities in our space. This is also true if one separates our Permian assets and looks at them in isolation. It's due to our continuing efforts towards tankless facility implementation, electrification, moving to centralized emergency flaring, and establishing a more aggressive inspection cadence than federal and state rules demand. Our entire organization is focused on these efforts. Our top-tier results are a reflection of our commitment and focus. We announced last night that our board of directors has authorized the $2 billion share buyback, which based on our current outlook, could be executed over the next 18 to 24 months. We are pivoting our capital return priorities to favor buybacks over the variable dividend. This is now growth of intensive study and debate about the macro environment we find ourselves in, investor feedback, and our viewpoint on a looming global supply-demand imbalance. We're not backing off our core pledge to return at least 50% of free cash flow to our owners in the form of our base dividend, buybacks, and variable dividend. The world has changed, and we find it prudent to adjust our cash return tactics accordingly. We think that one of the best, most accretive opportunities in the acquisition market lies in Coterra at our current market valuation. As a wise general once said to his troops, "If you find that the map doesn't match the terrain, go with the terrain." 2023, we're going with the terrain. We also announced the 3-year outlook with our release. Although this plan is not set in stone, it reflects our current multi-year activity schedule. It's based on real, ready-to-go locations, updated and calibrated type curves, and projects our current cost structure. As slide 6 in our investor deck shows, we have an active plan that generates an annual average 0%-5% BOE and natural gas growth and an annual average of 5% oil growth by investing $2.0 billion-$2.1 billion per year in each of the next 3 years on average. 2023 is year 1 of this multi-year plan. Basically, the 2023 plan that we announced last night sets up the 3-year cadence nicely. Production is anticipated to be relatively flat in 2023, we establish a cadence that will have significant impact on 2024 and beyond. Furthermore, we have optionality. The 2023 capital plan of $2.0 billion-$2.2 billion has off-ramps in the event conditions were to significantly degrade. We have balanced our program with some services under annual contract, while others are on a quarter-to-quarter basis. This provides flexibility as we navigate through the year. Our program is designed to be a guided missile, not a rifle shot. Coterra enjoys one of the industry's lowest cost of supply with our Marcellus gas assets. At the current commodity strip, our projected returns on our 2023 Marcellus program are outstanding. We have the projects and market takeaway at the ready. However, if conditions worsen and we choose to retrench, we can pare back. Our capital program is highly flexible depending upon commodity pricing and costs. This means that we can either significantly curtail total activity in capital or shift it from basin to basin as conditions warrant. We could pare back as much as 10% of our total capital this year without impacting 2023. However, it would lower our growth trajectory in the out years. That said, we do not manage our program based upon daily spot prices. Our outlook for 2023 is both guarded and optimistic. We're guarded owing to a muddled outlook on inflation and the inevitable impact that weather has on our natural gas business. We're optimistic because at the current and projected oil and natural gas prices, our project returns are excellent. Although they're not as robust as they were in 2022 owing to commodity downdrafts and the fact that we drilled some spectacular opportunities in 2022, our projected 2023 returns are excellent by historical standards. We've built a multi-year plan that invests through the cycles, generates modest, profitable growth, and checks the box for ability to withstand further commodity price erosion. The ability to confidently invest through the cycles is one of the many benefits of having a fortress balance sheet and assets with a low cost of supply. The flexibility of our multi-year program allows us to control those elements within our control and adjust those elements outside of our control. You'll also find a little more granularity on our asset inventory on slide 7 in our investor deck. As always, these are real locations with defined, calibrated targets, and type curves. These locations will be drilled. I hope that you will draw the conclusion from this that we do. Although one needs to continually high-grade inventory, Coterra is well-positioned for more than 15 years ahead. I would also like to draw your attention to our Anadarko in-inventory, which is significant and high quality. We are modestly increasing our activity in the Anadarko Basin in 2023 in order to bring forward some outstanding projects. There are more like them waiting in the wings. The Anadarko has a significant role to play in Coterra's future. Finally, with this release, we have closed the books on our reserve revision issue. This was a necessary step to level set our evaluation across our portfolio. We finished in the middle of the fairway that we had defined in our Q3 release. As we had promised, there are no new surprises in our end-of-year numbers. With that, I will turn the call over to Scott. Thanks, Tom. Today, I will discuss our fourth quarter and full year 2022 results, shareholder return strategy, finish with our 2023 outlook. During the fourth quarter, Coterra reported net income of $1 billion, discretionary cash flow of $1.4 billion, accrued capital expenditures of $483 million, and free cash flow of $892 million. Fourth quarter total production volumes averaged 632 MBOE per day, with natural gas volumes averaging 2.78 BCF per day and oil at 90.7 MBO per day. Oil finished 2% above the high end of guidance, natural gas hit the high end. The strong fourth quarter volume performance was driven by a combination of positive well productivity trends and improved cycle times. Fourth quarter turn-in-lines totaled 46 net wells in line with expectations. During the quarter, we returned 107% of free cash flow, which included $0.57 per share in cash dividends and $0.65 per share in the form of share repurchases. Share repurchases totaled $510 million in the quarter, marking the completion of our $1.25 billion program first announced in the first quarter of 2022. For the full year 2022, total production came in at the high end of guidance relative to our February 2022 guidance. Oil came in 2% above the high end, and natural gas came in 2% above the midpoint. Net wells online during the year were 3% below original guidance. Accrued capital expenditures, which were 16% above original guidance, totaled $1.74 billion and were driven by significant service cost inflation. During 2022, the company returned 85% of its free cash flow, 50% in the form of base and variable dividends, and 35% in the form of share repurchases. In total, the company returned $3.2 billion to shareholders or 18% of its recent market capitalization. After paying off $874 million of long-term notes during the year, Coterra finished the year with $673 million of cash and a net leverage ratio of 0.2x. The company has four manageable tranches of debt left, with maturities ranging from 2024 to 2029. Turning to a return of capital. As many of you read in our release and we have alluded to already, we have multiple updates on the capital return front. First, we increased our annual base dividend 33% to $0.80 per share. This reinforces the confidence management has in our business and our ability to perform across the cycles. It also reinforces our commitment to providing consistent and meaningful annual dividend increases to our owners. Next, after completing our $1.25 billion share repurchase authorization in 2022, we announced a new $2 billion share repurchase program. Using current commodity prices, this authorization will not be fully executed in a single year, but the $2 billion signals our commitment to the repurchase program and returning value to our shareholders. Lastly, we updated our return on capital priorities. We are reiterating our commitment to returning 50%+ of free cash flow to shareholders. We are prioritizing share repurchases ahead of variable dividends. Due to market conditions and the value proposition we see in our business, we believe buybacks are the best vehicle to return value to shareholders. Expect Coterra to pay its base dividend, pursue strategic buybacks, and supplement with variable dividends if needed to hit our minimum threshold. I will discuss the 2023 outlook. The company's 2023 capital is estimated to be $2.0 billion-$2.2 billion. This estimate includes approximately 10% cost inflation over the calendar year 2022 capital expenditures. Total full year 23 production on an equivalent unit of production basis is expected to be relatively flat to slightly down. Oil is expected to grow 2%, and natural gas volumes are expected to modestly decline 1% year-over-year. Drilling activity in 2023 is expected to be relatively consistent, with 5-6 rigs in the Permian, 2-3 rigs in the Marcellus, and 2 projects in the Anadarko. Frac activity will be up 31% year-over-year due to project and duct timing. The company average lateral length is expected to increase approximately 10% year-over-year, primarily due to longer laterals in our Upper Marcellus program. Since last summer, 2023 natural gas prices have fallen from a $6 annual average to a recent strip of $3. However, front month prices are near $2.16, and it is yet to be seen if the forward curve will hold. At the same time, service costs have not softened or adjusted. This dynamic has led Coterra to pursue a production maintenance plan in 2023, with anticipation of modest growth in our 3-year plan. The company has an industry-leading balance sheet and low breakevens to maintain consistent activity through the cycle. To put this in context, the company's corporate breakeven, which we define as free cash flow after paying the base dividend, sits at $45 WTI and $2.25 Henry Hub. The capital split in 2023 is expected to be 49% in the Permian, 44% in the Marcellus, with the remainder going to the Anadarko. On the heels of positive results in the Upper Marcellus in 2022, we are allocating 40%-50% of our 2023 Marcellus program dollars to further delineate the upper interval. This is above the 30%-40% range we discussed as the preliminary target in late 2022. This range is likely to be the higher end of the range for the Upper Marcellus versus the lower Marcellus foot over the 3-year period we laid out. Infrastructure timing, pipeline availability, and economics were all factors in increasing our allocation to the upper in 2023. Cost guidance for 2023 assumes that $ per BOE unit costs are flat to down across the board, largely driven by lower commodity prices outlook. Lastly, the future at Coterra is bright. Based on the current service cost environment, we estimate that if the company invests $2.0 billion-$2.1 billion per year over the next three years, it will generate a compound annual growth rate of 0%-5% for both BOE and natural gas and closer to 5% for oil. At current strip, this would generate cumulative free cash flow of approximately $7 billion or 35% of the current market cap. In summary, our first full year at Coterra was stellar. We met our planned production, expenses, and far exceeded revenues due to a small hedge book and robust pricing. For 2023, the price dynamic is different, but the engine of success is the same. Focus on operational execution of our high-quality inventory to generate strong returns and outsize shareholder returns. With that, I'll turn it back to the operator for Q&A. To ask a question, please press star one. Please limit yourself to two questions. Your first question is from Nitin Kumar of Mizuho. Please go ahead. Your line is open. Good morning, Tom and team, and thanks for taking our questions. Tom, I'd like to maybe unpack a little bit of your commentary around the 2023 capital budget. You said about 10% of that is really targeted towards growth with some off-ramps. Should we expect if you were to be in a maintenance mode, is your capital about $1.9 billion or $1.8 billion? How does that trend over time, particularly over the 3-year period? Yeah, Nitin, I'm gonna let Blake handle that. Yeah. Thanks, Nitin. yeah, our 2023 budget number represents the 3-year growth plan we've laid out, not a maintenance plan. If you look at slide 6, you'll see we plan to spend $2 billion-$2.1 billion per year over the next 3 years. What that does for us is provide 0%-5% BOE and gas growth on average annually, and oil growth at 5% on average annually. That's something we're choosing to do because we have a deep inventory of high return projects. If we chose not to grow and go into maintenance mode, that would drop to $1.8 billion-$1.9 billion per year over that same 3-year period at our current cost structure. Great. That's helpful. Then maybe this is for Scott, but, you know, we noticed the 90% of NYMEX realizations in Marcellus, which is pretty strong compared to your historical realizations. Could you maybe walk us through how that's coming about in 2023 and how sustainable that is going beyond? Actually, Nitin, I'll give that to Blake. He's over our marketing group now. Yeah. Thanks, Nitin. There's a couple things going on there. First, we've seen, just a reduction in the total basis with the rundown in NYMEX. We've seen that across all our indexes. It's also our portfolio. We have more contracts in 2023 pointed at premium markets than we did in 2022. We also have a good chunk of our portfolio that has floors under them, and at these lower prices, those floors come into play. It's really just overall great work by our marketing team. It's a, it's a really good tailwind for our NBU asset going into 2023. Great. Thanks, guys. Awesome. Your next question is from Umang Choudhary of Goldman Sachs. Please go ahead. Your line is open. Hi. Good morning, and thank you for taking my questions. Wanted to start off with your free cash flow allocation priorities. Would love your thoughts around allocation between share repurchase, your target of building $1 billion on cash on the balance sheet, and any thoughts around M&A. Sure. What we found in this past year is as we looked at, you know, we set out the door about $1.5 billion in variable dividends. Watching how the market reacted to that is what gave us pause, and we started researching. As we've talked internally and in Tom's prepared remarks, actually tying into your M&A comment right now, and we said this a year ago right out of the blocks, one of the best investments is investing in ourself because we think our assets are head and shoulders above everybody. Leaning in on the buyback, as that return of capital priority, but also increasing the base is what, you know, we have telegraphed over the years too, that we're gonna continue to do annual base dividend increases. From an overall perspective, it was an easy adjustment, still reaffirming. In terms of the $1 billion cash, that's a target for us to have. We had a couple of quarters when we were right at $1 billion. What took us below is the decision of getting to our debt level target of right around $2 billion. We will balance building the cash balance back up to $1 billion with the buybacks meeting the 50%. Remember the stat I gave, we returned 83% of our free cash flow, so we far exceeded the 50% commitment last year. That's very helpful. Thank you. Then maybe to follow up on Nitin's questions, on flexibility of the capital program to changing macro conditions. What kind of flex do you have in your program over the next three years? Then any color you can provide on the recent cost trends would be helpful. Thank you. I'll handle the first part, and Blake Sirgo can talk about cost trends. We have tremendous flexibility. You know, our teams worked really hard at the latter half of last year, building in flexibility. As you can recall, premium equipment was not available unless you were willing to sign a long-term contract. We had a lot of services that came off contract, and in order to keep them, we had to renew it. We, you know, our operations team worked really hard to give us flexibility. We have some services under annual contract and some that we have the option quarter to quarter. The longest term we have is an annual contract. If you look out at a 3-year program, we have tremendous flexibility. You know, the nice thing about sitting on top of Coterra's assets and our three business units is we can pivot rather nimbly depending on conditions. Right now, we like where we sit, but we are going to look at it continuously during the course of the year. Yeah. On the cost trends, the 10% we're showing for 2023 is really a reflection of those contracts we entered into in late 2022. It sure feels like the market's starting to soften. You know, there's less talk about price increases, more talk about costs holding flat. If activity starts to drop across the lower 48, we'll be looking to claw some of those costs back. Very helpful. Thank you, guys. Your next question is from Arun Jayaram of JP Morgan. Please go ahead. Your line is open. Good morning, Tom and team. I wanted to get maybe some more thoughts on the three-year kind of outlook that you provided. I know in 2023, the CapEx budget includes about $180 million for, call it growth CapEx. This year, you guys have provided an outlook for, call it 168 net wells at the midpoint. Would that three-year outlook call for a similar, you know, call it, wells tied to sales or do you have, you know, increases baked in to deliver, call it that high single digits oil growth in 2024 and 2025 based on this outlook? Arun, I don't have the actual well count in front of me, but it's fairly flat level of activity is what we're projecting. I think you could really see a level set in terms of the 23 activity going forward. You know, just an editorial comment, Arun. You know, if there's one thing that many of us have learned is that in this shale era, this stop-start around commodity prices is really damaging to your cost control, your operational cadence. Quite frankly, I think as an industry, we've typically kind of gotten that exactly wrong in terms of when we invest and when we contract. The nice thing about Coterra is because our assets have such robustness at low commodity prices, we can maintain more of a regular operational cadence. That's what we're going to do, and that's a strategic pivot for us. It's why we put Coterra together. Whether that operational cadence has our current rig count or a rig count less or, you know, a rig higher, we're gonna try to maintain a steady cadence and not wake up every day with our hair on fire when we read the paper. We can afford to prosecute this business the way this business needs to be prosecuted. Great, Tom. My follow-up, you know, your Delaware Basin team had a good year in terms of, you know, well productivity, which you highlight, you know, in your deck. I wanted to get some thoughts. I mean, well productivity has been a concern from the buy side, including, you know, from one of your, you know, partners called in Culberson County, who highlighted that on their call. What are your thoughts on sustaining, you know, this level of well productivity in the Delaware on a go-forward basis? How does the Harkey Sandstone kind of fit into that, you know, overall development scheme? We do not see a change in our Delaware productivity. You know, one of the big differences, as I said in my opening remarks, is in 2022, we just drilled a couple of absolutely lights out outstanding projects. I'm talking about projects with you know, over 10 wells that average thousands of barrels a day. You know, we don't have tons of those, and we drilled a couple of them in '22, and that was part of the productivity in '22. Specifically to your question about well-to-well interference, when it comes to the Wolfcamp and Harkey, we generally see that as one petroleum system, and there will be some degree of pressure communication between the Wolfcamp and Harkey, depending on where you are in the basin. We do not see that as a factor that degrades overall well productivity. We typically stage that development within, you know, reasonable proximity of time. Our thinking on that matter is that having the two landing zones does not interrupt or impede your overall recovery out of that drilling spacing unit. You know, we don't see that as a significant issue for the Wolfcamp Harkey. You know, I think the big answer to your big question is, over that three-year landscape, we don't see a significant change in our Delaware productivity. Great. Thanks a lot, Tom. Your next question is from Jeanine Wai of Barclays. Please go ahead. Your line is open. Hi. Good morning. Thanks for taking our questions. Hi, Jeanine. Hi. Good morning. Our first question, may be a macro question, kind of following up on Umang's question about capital allocation. We realize it could be a moving target, but could you provide your view of mid-cycle natural gas prices? We know that Coterra certainly isn't reactive to the price that we see on the screen, and you have good returns even at low prices that are stress-tested. You know, at what point do you really start to rethink capital allocation? Well, you know, look, mid-cycle is kind of in the beholder. Everybody says the word mid-cycle, you know, we'd rather you didn't ask us what the number was, but you do, and we'll answer it. Our current mid-cycle that is our walking around number is $2.75 natural gas, our assets are really robust $2.75 natural gas. We, you know, we As we said, Jeanine, we have the ability to move it around. You know, the nice thing about having both a deep oil and natural gas inventory is, although we produce a lot of natural gas in the Delaware Basin, it's kind of a by-product, it's not really a function of the gas price. But right now, our returns are pretty good across our portfolio. Okay, great. Thank you. Maybe just following up to Arun's question on the 3-year plan. Oil is expected to grow that 5%, gas anywhere between the 0%-5%. There's certainly some nuance to the plan in the Marcellus this year with the Upper Marcellus getting a bigger mix of the CapEx there. You know, what really determines in the 3-year plan where gas kind of lands in that range of 0%-5%? You addressed 2023 really well. We're thinking, for example, it seems like Marcellus productivity per foot is getting worse this year, but 2024, 2025 could be better. The range, is it primarily commodity driven? We're just trying to understand kind of the messaging on gas since the solid growth on oil seems to be pretty clear. Thank you. Well, we're kind of in a shoulder period in natural gas right now. That's your outlook on natural gas. In 2024 we'll have LNG export come online. We are kind of in a wait and see mode on natural gas. We're long-term, very bullish because of the world's need for natural gas, and particularly the world's need for U.S. LNG exports. We're optimistic that that's becoming more and more apparent to more and more policymakers, and we remain ready to accelerate our natural gas assets. You know, we're in the mid-40s on Upper Marcellus this year on a total footage. You know, we've talked openly that the Upper Marcellus doesn't have the productivity per foot of the Lower Marcellus. That's just something that's a fact of our assets, still outstanding, still very good, and we're gonna continue to develop it as we go. All right. Great. Thank you, Tom. Your next question is from Doug Leggate of Bank of America. Please go ahead. Your line is open. Thanks. Good morning. First of all, guys, I'd like to acknowledge your disclosure, the visibility you've given us in your portfolio last night. Well, I think your share price is saying it all. Thank you for that because it really ticks a lot of boxes on inventory depth, cash breakevens, free cash flow capacity. It basically allows the market to value your company. Thanks to whoever had the initiative to do that. It's brilliant. Thanks for that. That's my first just general comment. I've got two questions because the information is never enough. I guess my first one would be on slide number 7. Can you give us some commodity benchmarks around your ranges just so we can bookend what's going on in slide 7 on the inventory? That's my first one. When you say commodity benchmarks? The inventory ranges you've given, Tom, are. Yes. Yeah, no, I've got that in front of me, Doug. We have quite a bit of robustness in our inventory, and we typically run our inventory at multiple price files. I'm looking at a permutation in front of me that's run at $60 oil and $3 gas long term, and $85 oil and four and a quarter gas long term. I will say when we go to $3 or less, we do assume some reduction in capital. Currently we say, all right, if we're gonna say $60 oil, $3 gas, we're gonna take 70% of current capital expenditures. The $85, four and a quarter is at current cost. You know, depending on where you want to cut it off, if I say, all right, how much of that hurdles at a 1.25 PVI10, which I think is a reasonable long-term inventory cutoff. We've been using 1.5 in a lot of our disclosure, but I'm gonna give you 1.25. At 60 and 3, 75% of our total inventory would hurdle at a 1.25 PVI10. At 85 and 4.25, 91% of our inventory would hurdle at a 1.25 PVI10. At 85, 4.25, that is the current cost. We have a fair amount of downside protection on this inventory. Great, great color. Thanks, Tom. I appreciate that. I guess my follow-up is, I really just wanted to ask you to walk, you know, just the slight change in messaging over share buybacks. I think you all know our view on variable dividends for a depleting business with a finite inventory. I won't get on my soapbox, but it seems that you guys are pivoting to recognize that there, you know, there probably is some value in your stock here. Can you walk us through the investor feedback that you I think is how you described part of your decision to make that shift? I'll leave it there. Thanks. Well, Doug, we've heard very mixed signals out of our investor base. I mean, you know, some people want us to do A and some people want us to do B. We've also looked at the market response to the variable dividend and I think that's a strong signal as to what the market's looking for. You know, we listen to our critics, and we think about it, and we really do and have an honest attempt to get better and adopt the best approach. You know, we think that long term, buyback not only is the best acquisition opportunity in the market when we look at Coterra stock, but it's also highly accretive to our long-term owners. And that kind of checks two boxes. You know, I won't tell you it was a casual decision to readjust our priorities, but we're very, very confident that in 2023 it's the right decision. Appreciate the color. Guys, thanks very much indeed, and congrats on all your new disclosure. Thanks, Doug. Your next question is from David Deckelbaum of Cowen. Please go ahead. Your line is open. Morning, Tom and Scott. Thanks for taking my questions today. Hi, David. I wanted to. Hello. If I could just dive into the Upper Marcellus a little bit, just to better my understanding here. This year, it sounds like the mix is going to be higher relative to the overall Upper versus Lower mix in the next several years. I guess I'm curious, based on the wells that you have in the plan now in the Upper, how much of the sort of resource do you think that you're going to be de-risking this year relative to what you have sort of envisioned overall? How many of those locations are gonna be in areas where the Lower Marcellus has already been depleted? I don't have the answer at my fingertips as far as what we're gonna de-risk. We are trying to space our upper Marcellus pads around our asset, and we're developing a very good appreciation of how much of it will ultimately be developed. I will say that our viewpoint on that hasn't changed based on everything we've done and collected. You know, there's a lot of drilling in the upper Marcellus. What we're really experimenting with now is longer lateral length, well spacing, different completion designs, and how it will behave when we put wells side by side. Thus far, we've had great feedback, and it's not changed our viewpoint of the asset. as far as the upper-lower mix in future years, that's governed by a lot of things. We still have a fair amount of lower left and, you know, we'll be pivoting back to it. You know, that's more a function of our infrastructure availability and, you know, we're trying to manage that so that we keep our line pressures reasonable, and we don't overdrive the system. Thanks, Tom. I guess my follow-up to that is just as you look to that ramp of 100 million a day or so in the next couple of years, I suppose that assumes sort of similar activities in the Marcellus. Is that just reflecting a quality mix between having more of the lower and perhaps, just better infrastructure availability? Yeah. I'm not following your $100 million a day, David. Sorry. What is that referring to? I thought that I saw in your presentation that the implication was that you would get. Oh. Oh, yeah. from 38-39. Yeah. Yeah. Well, yeah, I see what you're saying. No. Look, we would love to get our natural gas back on a growth profile. That's just an outcome of our three-year plan. It's just an outcome of the projects we're drilling, the staging of the completions, and what we think it'll deliver. You know, it's also a function that the modest extra investments we're putting in the ground this year really do pay off in the next two years. Some of that's just fruits of seeds we're planting this year. All right. Well, best of luck with the garden. Thanks, Tom. Thank you. Your next question is from Derrick Whitfield of Stifel. Please go ahead. Your line is open. Good morning, Tom and team, congrats on a strong year-end. Thank you. For my first question, I wanted to focus on your 2023 capital program. If we were to assume flat commodity price, a flat commodity price environment, how would you expect service costs to change across your operating areas? More broadly, where are you seeing the greatest headwinds and tailwinds from a service cost component perspective? Derrick, this is Blake. I'll take that one. It's hard to pin a service cost to a commodity price. I mean, it's really ultimately a function of activity and how much services are available on the market. We're seeing some softening. You know, I'm happy to say we've seen a little bit in rig rates here recently, and that's a good sign. We've seen a softening in casing, our OCTG. Going out three to six months, we're starting to see some price coming down, and that's a good sign. You know, ultimately, it's gonna be a function of activity across the lower 48. All rigs and crews have wheels, and they will travel. We'll see where activity goes. Terrific. I just one right follow-up, maybe shifting over to the Anadarko. Your well results on slide 17 and 18 seemingly beg for higher capital, particularly in the up-dip part of the play. Could you perhaps speak to the updates you've integrated in your design and spacing at Leota Clark? Yes. specifically, Leota Clark, you know, was an outgrowth of a lot of work we've done over the years. We did space those wells a little farther apart. One of the things we also learned is to put our wells a little further away from parent wells, and very pleased with the results. you know, as we look ahead in our three-year plan, the Anadarko has a few very nice projects this year. We take a little pause, we start up January one of 2024 with additional activity. We're, you know... As you look at that inventory slide, these are high-quality locations, really begging for more capital, quite frankly. The team is making it really hard for us, and as we ask them to do, they've come forward with some really, really nice projects and inventory. You know, we're in the progress of trying to manage an embarrassment of riches. Terrific. Thanks for your time and color. Your next question is from Matt Portillo of TPH. Please go ahead. Your line is open. Good morning, all. Hi, Matt. Just to tease out on kind of a consistent thread here, Tom. There's obviously a lot of interest from the broader market in gas capital allocation. Just wanted to circle back around to that. You mentioned the mid-cycle price on gas of $2.75. If that plays out, could you just give us a little bit of color on how you think about Marcellus capital allocation heading into 2024? And the reason we ask is we know you're very return focused, and even at a $3.50 deck, the Permian still has better overall returns relative to the Marcellus based on your slides. Just curious if there's some flexibility in the program once you get through your service contracts, where the Marcellus may receive a little less capital in 2024 if that $2.75 mid-cycle price plays out? Well, if $2.75 were the price, I think that's probably something we'd look at seriously. You know, our current plan has fairly flat level of activity in the Marcellus, our intention is to soldier on. You know, if we look very carefully at the oil/gas ratio and the return differential and, you know, we're gonna pivot and try to find the best returns within our portfolio. You know. Perfect ... the oil/gas ratio last year was 10 to 1. It's currently 30 to 1. You know, we talk about mid-cycle pricing. You know, that mid-cycle ratio is really what we're looking at. We don't wanna react... You know, we don't wanna knee-jerk near term. We've got the wherewithal to be patient on this. That makes sense. Just a follow-up to the Marcellus. I know you guys have talked about the frac barrier and the ability to develop the zones without co-development here. Could you just give us maybe a little bit of color on the program for the Upper Marcellus? I know you've talked about 40% for this year, but in the three-year outlook, how should we be thinking about the percentage at a high level of the Upper Marcellus wells in that program in 2024 and 2025? In that three-year plan, the Upper Marcellus is the highest percentage this year that we're currently projecting over the next three years. you know, in the out years, 2024 and 2025, and our current plan is, the Upper Marcellus is gonna be about 30%-40% of our total program. you know, I will just reaffirm, we stand by our statement that that frac barrier is indeed a hydraulic isolation between the two units, which does give us the luxury to stage the development in the most prudent way. Thanks so much. Your next question is from Neal Dingmann of Truist Securities. Please go ahead. Your line is open. Morning, all. Thanks for getting me in. My first question, Tom, for you and the gang is just on your Permian project size, and specifically, I was looking at that slide. It looks like now, what would you consider kind of the 8-10 well pads now as the most optimal? Was wondering, has that increased due to sort of just overall cost out there, efficiencies, or what has driven, you know, these larger project development? Well, I'll chime in, and then Blake will come in as well. You know, we. That 8 to 10 well project size, we didn't come up with that through some deep thinking. We kind of just happened, you know, operationally as we look at cycle times, we look at facility design, that seemed to be what looked to work. You know, Delaware is a little different beast than a lot of other basins you'll look at. We have a single pad in the Delaware that we're flowing back, that is flowing back in excess of 200,000 barrels of water a day. Single project. You know, pad design in the Delaware is a function of a lot of things, one of which is, infrastructure. Yeah. I'll just tack on. You know, really the wells per pad is an outcome of always looking for efficiency. That's really what we're constantly looking for on the cost side. The more wells per pad we get, the more coming we can do. It just drops our per well cost, our dollar per foot cost. Our teams have got really creative. You know, we have pads now that have wells going to the north and wells going to the south. We come back, as Tom said, after those 200,000 barrels declines, and we add in new zones and plug those into the same facilities. Probably our biggest limit is just kickouts on drilling, and there's a cost associated with that, and that's really what we measure when we determine how many wells are we gonna squeeze on one pad. Neal, I wanna correct myself. That projects and pads are, it's one pad is producing 100,000 barrels a day. I said it's the... I was talking about project. One pad is producing 100,000 barrels of water a day. either way, that's big. That's great clarification, Tom. It is big. Yeah. That's crazy. In Marcellus, we produce 5,000 barrels a day in the whole field. All right. My second question is then on your Marcellus delineation plan, specifically, I saw in the release you all mentioned about 40% of the Marcellus plan is delineation nature. Is this plan gonna cover most of the broader position, or are there some key areas that you're delineating? You know, I know you're not gonna give 2024 guide. I'm not looking for that, but will that delineation continue to that percentage well into next year as well? You know, this year we are. We do have a pretty good delineation across the field that we're testing Upper Marcellus in. Really it's a function of takeaway and infrastructure, too. You know, we're careful where we bring that on. You'll kind of see that theme in the Upper as we go forward, where we put those locations similar to the Lower, how we've done in the past. Infrastructure is a real guiding light there. Yeah, yeah. Neal, I'm looking at the map right now of our Upper Marcellus projects, and it's a pretty good scatter shot over our acreage. I think, you know, you'll all be pleased at our delineation. I also want to remind everybody that infrastructure's important in these plans, and we'll have a new compressor station opening here in the next year or two in the Marcellus, and that's always an opportunity for further extension. Great answer. Look forward to hearing all the details. Thanks, Tom. Your next question is from Kevin MacCurdy of Pickering Energy Partners. Please go ahead. Your line is open. Hey, good morning. I was wondering if you can give some color on how you plan to execute the share buybacks. Will there be a set amount that you do each quarter based on your free cash flow, or are you gonna be more opportunistic based on your internal nav? We're gonna, obviously based on, like you said, the internal evaluations due. We're gonna continue to, just like we did with the last one, focus more on the opportunistic look at the marketplace, where we're trading versus our perception of where we should be trading. Again, we do have a commitment. We're not gonna become programmatic in doing it. It'll still be more opportunistic than anything else. Great. Then just if I can, a question on the multiyear outlook. What would you say is the main driver of the increased oil production? Obviously, you're gonna put on more wells. Are there any changes in productivity or drilling in more productive areas or higher working interest areas that are contributing to that impressive growth? Well, a huge driver is the extra capital we're putting in this year. We're setting some things up for next year that we're quite excited about. You know, look, we love our Delaware assets. You know, we love all of our assets. Because of oil prices, it just makes sense to put that little extra effort forward this year and reap the rewards. Great. Thank you for taking my questions. Your next question is from Leo Mariani of Roth MKM. Please go ahead. Your line is open. Yeah. Hey, guys. Wanted to ask a little about the CapEx outlook here. You guys are talking about, you know, $2 billion-$2.2 billion, you know, this year in terms of the range. I was hoping to get a little bit of color around in terms of what puts you at the higher end versus the lower end. I'm assuming it might just be service costs. As I look at the three-year outlook, you guys are expecting that to come in slightly to kind of more $2.0 billion-$2.1 billion in the next couple years. Just wanted to get a sense of why that's coming down a little bit. Is there any expectation that service costs, you know, might come in? Obviously, you talked about some of the trends maybe starting to look favorable. Yeah. I'll, Leo, this is Blake. I'll take that one. The, you know, the 23 program is all modeled at current cost, you know, and that would put us maybe just a little north of the midpoint, not assuming any deflation right now. We'll see where that goes. The 2 to 2.1 going out in the next 3 years, it's really more a function of the project selection and the asset mix that comes in and comes out. Some parts of the assets have higher dollar per foot, some have lower, and that's just coming in and out throughout that 3-year program. Okay. That's helpful. Just wanted to follow up on some of the comments you guys made about the variable dividend versus the buyback. You know, just wanted to get a sense, I know you guys are gonna continuously monitor this, but, you know, could we have an outcome this year where we get very, very little variable dividend and, you know, the buyback increases, you know, rather significantly versus kind of where it had been in the second half of 2022? Obviously, you know, the stock, while it's doing well today has come in quite a bit off the highs, you know, from last year. Just trying to get a sense if you guys are really gonna kind of lean pretty hard on the buyback this year and do kind of very little on the variable dividend depending on how, you know, things play out? I think that Leo, I think that's a good assumption. The priority, as we said, is the base first, buyback second, and then fill in if needed with the variable dividend. To the core of your question, we're focused particularly because we agree with you. Our stock has come in quite a bit, and we see a great opportunity in that. If you press me today, I would say the direction you're going is correct. Okay. Appreciate it, guys. Thanks. Your next question is from Paul Cheng of Scotiabank. Please go ahead. Your line is open. Hi. Hi. good morning. Morning. Two questions, please. One question is, going back into the buyback and fixed dividend. Let's assume that later this year that you already raised your cash balance to $1 billion. At that point, should we assume that the excess cash will be essentially both for the shareholder return, and that means that if you end up that going to be above 50%, or that even reach that level that you may want to further strengthen your balance sheet. Trying to understand that once you reach that level, I mean, what kind of distribution that we should assume? Secondly, that Tom, can you talk about, you have a pretty huge inventory backlog already. Bolt-on acquisition is something that, you guys think, is attractive or that is important for you over the next couple of years, or that you would be, still focusing, on your existing asset? Thank you. Paul, I'll take the first part. It's not that clear of a formula. As you watched us through this year, again, our minimum commitment was 50+%. As we just highlighted, we returned 83%. There's not a magic point that we get $1 billion in cash, and then all of a sudden we start going. The $1 billion in cash is a target. The 50+% of cash flow is a rule, so to speak, and then we have flexibility around how we deliver that and how much more we want to deliver based on market conditions. You can't pinpoint to something that once we get to this point, we're gonna start doing this. We have all those options on the table, and we'll continue to use all those options, but the priorities right now is the 50%+ base dividend and buyback first, and we'd like to get our cash balance up. What the cash balance does, being a little bit higher, affords us flexibility in the question that you're asking Tom. I'll take that question. You know, inventory is always an important issue. As I've said in the past, having a long inventory really gives you the opportunity to run your program with only solid financial and operational considerations and not be panicked about some kind of a runway that's short. We have a very deep inventory and we have the luxury of being able to run our program based on the best financial returns. That said, we're a learning organization, and we're constantly looking for opportunities. We would love to find bolt-ons that we could hand to our operational teams. You know, we're very proud of our operational teams and their ability to integrate, operate smartly, and really bring a hidden value forward. We're gonna constantly look, but, you know, M&A is a perilous territory. We typically wanna have some advantage. That advantage can be information advantage, it can be operational advantage, it could be geographic advantage. We're probably not gonna be showing up to auctions and trying to outbid people that have the same information we do. We'll be opportunistic, but we're, you know, blessed with the luxury of not having to do something, and that's a nice place to be. Your next question is from Charles Meade of Johnson Rice. Please go ahead. Your line is open. Good morning, Tom Jorden and Scott Schroeder. Thanks for fitting me in. I just have one more question on the buyback, and I know you guys have covered a lot of territory on it, but I think it's an important shift. Scott Schroeder, I know this is a conversation that you've engaged in, you know, for a long time, but the sense I get is that in the current environment, you guys are tilted hard towards the buyback, and I think you've been clear on that. My question is about whether you guys view this pivot as a durable pivot across time and also across price. If you are thinking about it as a durable pivot, maybe you can share kinda up to what price you view it as being durable. Well, Charles, that's a nice try. I won't give you the price. I think it's fair to say it is more durable because you see the technical term, the stickiness of buybacks because it has a lasting impact over all cycles and well into your future. You know, I'd be lying if I didn't say I'd run the math in my head based on the average of what I bought in last year. If I had used that variable dividend money, what would my shares outstanding be? That number kind of intrigues me. Can't undo what we did last year. I think where you're leaning is I view this as more durable because it is, I think, the best long-term solution. There will be points and disconnects in the market where it may not make sense. I'd love to have that challenge where the whole perception is the market, the stock got ahead of itself. We're a long ways away from that. We are also going to make the best decision quarter by quarter and be prepared to pivot. We're not making some holy pledge for all time. What we're saying is we're reaffirming our commitment to return cash to our owners, and we think there's a better way to do it in 2023, and we're very confident with our move this morning. Got it, Tom and Scott. That's it for me. Thank you. We have completed the allotted time for questions. I will now turn the call over to Tom Jorden for closing remarks. Thank you all for joining us. We look forward to executing, showing you that we're doing what we believe, and we're gonna deliver what we promised. Thank you all very much. This concludes today's conference call. Thank you for your participation. You may now disconnect.