Thank you, and 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 have joined us for our fourth quarter conference call. We're looking forward to a fruitful discussion on Coterra's performance, outlook for 2023, three-year outlook and our plan for capital return. We had an excellent fourth quarter and full year in 2022, driven by superior asset performance, good execution and favorable commodity prices. 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 required careful planning, intelligent engineering, great field coordination, perseverance and a lot of effort on the part of our operational staff in all three regions. The lack of significant downtime was also aided by collaboration between our business units. We brought our teams together earlier in the fall to share experiences and best practices on weatherization, and 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 the 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 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 sector. This remains true even if one looks at our Permian assets in isolation. It's due to our ongoing 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 committed to these efforts. Our top-tier results are a reflection of our dedication and focus. We announced last night that our Board of Directors has authorized a $2 billion share buyback, which, based on our current outlook, can be executed over the next 18 to 24 months. We are pivoting our capital return priorities to favor buybacks over the variable dividend. There has been a robust discussion 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 base dividends, buybacks and variable dividends. The world has changed, and we find it prudent to adjust our tactics accordingly. Furthermore, we believe 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. In 2023, we’re going with the terrain. We also announced the three-year outlook with our release. Although this plan is not set in stone and reflects our current multi-year activity schedule, it's based on real ready-to-go locations, updated and calibrated type curves, and reflects our current cost structure. As Slide 6 in our investor deck shows, we have an active plan that generates an annual average of 0% to 5% Boe and natural gas growth and an annual average of 5% oil growth by investing $2.0 billion to $2.1 billion per year over the next three years on average. 2023 is the first year of this multi-year plan. The plan we announced last night sets up the three-year cadence nicely. Although production is anticipated to be relatively flat in 2023, we established a cadence that will impact 2024 and beyond significantly. Furthermore, we have optionality. The 2023 capital plan of $2.0 billion to $2.2 billion has off-ramps in the event conditions significantly degrade. We have balanced our program with some services under annual contract while others are on a quarter-too-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 costs of supply with our Marcellus gas assets. At current commodity prices, our projected returns on our 2023 Marcellus program are outstanding. We have the projects and market takeaway ready. However, if conditions worsen and we choose to retrench, we can pare back. Our capital program is highly flexible depending on commodity pricing and costs. This means we can either significantly curtail total activity and 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 on daily spot prices. Our outlook for 2023 is both guarded and optimistic. We're cautious due to a muddled outlook on inflation and the inevitable impact of weather on our natural gas business. We're optimistic because at current and projected oil and natural gas prices, our project returns are excellent. Although they're not as robust as they were in 2022 due to commodity downdrafts and the fact that we drilled some spectacular opportunities in 2022, our projected 2023 returns are excellent by historical standards. We have built a multi-year plan that invests through the cycles, generates modest profitable growth, and checks the box for the ability to withstand further commodity price erosion. The ability to confidently invest through cycles is one of the many benefits of having a robust balance sheet and assets with a low cost of supply. The flexibility of our multi-year program allows us to manage 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 same conclusion from this as we do. Although it's necessary to continually high-grade inventory, Coterra is well positioned for more than 15 years ahead. I would also like to highlight our Anadarko inventory, which is significant and high quality. We are modestly increasing our activity in the Anadarko basin in 2023 to bring outstanding projects forward. There are indeed more like this 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 step was necessary to level set our evaluation across our portfolio. We finished in the middle of the fairway that we had to find 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, the shareholder return strategy, and then 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, and 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 dividend 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 our 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, with 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 on 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 our return of capital, we have multiple updates on this front. First, we increased our annual base dividend by 33% to $0.80 per share. This reinforces the confidence management has in our business and our ability to perform across cycles. It also demonstrates 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 represents our commitment to the repurchase program and returning value to our shareholders. Lastly, we updated our return on capital priorities. We reiterate our commitment to returning over 50% of free cash flow to shareholders. However, 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 dividends, pursue strategic buybacks, and supplement with variable dividends if needed to meet our minimum threshold. In terms of our 2023 outlook, the company's capital expenditure is estimated to be between $2.0 billion and $2.2 billion. This estimate includes approximately 10% cost inflation over the capital expenditures of calendar year 2022. Total full-year 2023 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 by 1% year-over-year. Rolling activity in 2023 is expected to be relatively consistent, with five to six rigs in the Permian, two to three rigs in the Marcellus, and two projects in the Anadarko. Frac activity will be up 31% year-over-year due to project and DUC timing. The company average lateral life 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 decreased from an average of $6 to a recent strip of $3. However, front month prices are around $2.16, and it remains 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, anticipating modest growth in our three-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 allocated to the Anadarko. Following positive results in the upper Marcellus in 2022, we are allocating 40% to 50% of our 2023 Marcellus program dollars to further delineate the upper interval. This represents an increase from the preliminary target of 30% to 40% range discussed in late 2022. Infrastructure timing, pipeline availability, and economics were all contributing factors in increasing our allocation to the upper Marcellus in 2023. Cost guidance for 2023 assumes that dollar per BOE unit costs are flat or down across the board, largely driven by lower commodity prices. Lastly, the future of Coterra is bright. Based on the current service cost environment, we estimate that if the company invests $2.0 billion to $2.1 billion per year over the next three years, it will generate a compound annual growth rate of 0% to 5% for both Boe and natural gas and closer to 5% for oil. At current strip, this strategy would generate accumulative 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 and 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 remains the same, as we focus on operational execution of our high-quality inventory to generate strong returns and outsized shareholder returns. With that, I’ll turn it back over to the operator for Q&A.

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. Thanks for taking our questions. Tom, I'd like to 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? And how does that trend over time, particularly over the three-year period?

Nitin, I’m going to let Blake handle that.

Yes. Thanks, Nitin. Our 2023 budget number represents the three-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 to $2.1 billion per year over the next three years. This setup provides 0% to 5% Boe and gas growth annually on average, with oil growth of 5% on average annually. We're choosing to do this 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 to $1.9 billion per year over that same three-year period at our current cost structure.

Great. That's helpful. And then maybe this is for Scott, but we noticed the 90% of NYMEX realizations in the 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.

Yes. Thanks, Nitin. There's a couple of things happening there. First, we've seen a reduction in the total basis with the decline in NYMEX. We've observed that across all our indexes, but it's also our portfolio. We have more contracts in 2023 directed at premium markets than we did in 2022. We also have a significant portion of our portfolio that has floors under them. At these lower prices, those floors come into play. So it's really just overall great work by our marketing team. It's a positive trend in the U.S. going into 2023.

Great. Thanks, guys.

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. I wanted to start off with your free cash flow allocation priorities. I’d 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 that we set out to do about $1.5 billion in variable dividends. Watching how the market reacted to that gave us pause and started some internal discussion. As we've discussed, one of the best investments is investing in ourselves because we think our assets are superior to others. Leaning into the buyback as that return of capital priority, alongside increasing the base dividend is what we've telegraphed to our shareholders over the years. From a broader perspective, it was a straightforward adjustment while reaffirming our commitments. In terms of the $1 billion cash target, there were a few quarters when we were right at that level. What took us below was the decision to achieve our debt level target of about $2 billion. We will balance building the cash balance back up to $1 billion with buybacks, ensuring we meet the 50% commitment. As a reminder, we returned 83% of our free cash flow last year, so we far exceeded the 50% commitment.

That's very helpful. Thank you. And then maybe to follow up on Nitin’s question regarding the flexibility of your capital program to changing macro conditions, what kind of flexibility do you have in your program over the next three years? Any color you can provide on the recent cost trends would also be helpful. Thank you.

I'll handle the first part, and Blake can discuss cost trends. We have tremendous flexibility. Our teams worked diligently in the latter half of last year to build in flexibility. As you may recall, premium equipment wasn’t available unless you signed a long-term contract. A lot of services came off contract, and in order to maintain them, we had to renew. Our operations team worked really hard to give us flexibility. Now, we have some services under annual contract and others on a quarter-to-quarter basis. For our three-year program, we have tremendous flexibility. The advantage of sitting atop Coterra's assets and our three business units is we can pivot nimbly depending on conditions. Right now, we like where we stand, but we will assess it continuously throughout the year.

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 seems the market is starting to soften. There's less talk about price increases, or 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 JPMorgan. Please go ahead. Your line is open.

Good morning, Tom and team. I wanted to get some more thoughts on the three-year outlook that you provided. I know in 2023, the CapEx budget includes about $180 million for growth CapEx. This year, you guys have provided an outlook for about 168 net wells at the midpoint. Will that three-year outlook call for a similar number of wells tied to sales, or do you have increases baked in to deliver high-single digit oil growth in '24 and '25 based on this outlook?

Yes, Arun, I don't have the actual well count in front of me, but it's a fairly flat level of activity we're projecting. You could consider a level set in terms of the 2023 activity going forward. An additional comment: If there’s one thing many of us have learned, it’s that in this shale era, the stop-start cycle around commodity prices is detrimental to cost control and operational cadence. I think as an industry, we’ve traditionally managed this incorrectly relative to when we invest and what we can track. The good news is Coterra's assets are robust at low commodity prices, allowing us to maintain a regular operational cadence. That’s why we put Coterra together. Whether that operational cadence aligns with our current rig count or differs, we will try to maintain a steady approach without being overly reactive.

Great, Tom. And my follow-up: your Delaware basin team had a good year in terms of well productivity, which you highlight in your deck. I wanted to get your thoughts on sustaining this level of well productivity in the Delaware moving forward. How does the Harkey Shale fit into that development scheme?

We do not see a change in our Delaware productivity. In 2022, we drilled a couple of outstanding projects with over 10 wells averaging thousands of barrels a day. While we don't have many of these projects, we had a couple in '22 that contributed significantly to our productivity. Regarding well-to-well interference between the Wolfcamp and Harky, we generally see this as one petroleum system. There will be some degree of pressure communication depending on the location in the basin. However, we do not see this affecting overall well productivity. We typically stage that development in reasonable proximity over time. Our strategy is to develop across both landing zones without compromising overall recovery from the drilling spacing unit. Hence, we don't anticipate significant issues affecting 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 is 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 maintain good returns even at low prices. But at what point do you start to rethink capital allocation?

Well, mid-cycle is subjective. Everyone has their definition. We’d prefer you didn’t ask us for a number, but you do, and I will answer it. Our current mid-cycle gas price would be around $2.75. Our assets perform exceptionally well at that price point. As we’ve previously stated, we have the flexibility to adjust our operations. Having both oil and natural gas inventories allows us to prioritize based on market conditions. Currently, our returns across our portfolio remain solid.

Okay, great. Thank you. And then maybe following up on Arun’s question regarding your three-year plan, oil is expected to grow at 5%, with gas growth anywhere from 0% to 5%. There appears to be some nuance in the Marcellus this year, with the upper Marcellus receiving a higher share of the CapEx. What really determines the gas outlook within that 0% to 5% range? There's been indications that Marcellus productivity per foot may be declining this year. However, ‘24 and ‘25 might show improvements. Is this range primarily commodity-driven? We're trying to understand the messaging around gas since oil growth seems clearer.

We are currently in a transitional phase for natural gas, especially with LNG exports coming online in 2024. We're cautiously optimistic about the long-term demand for natural gas, especially for U.S. LNG exports. It seems increasingly clear to policymakers. We’re prepared to accelerate development of our natural gas assets. We’re operating in the mid-40s in the upper Marcellus currently in terms of total footage. It’s worth noting that the upper Marcellus has historically lower productivity per foot compared to the lower Marcellus. However, production in that sector is still robust, and we will keep focusing on its development.

Alright, 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, I'd like to acknowledge your disclosure, the visibility you've given us around your portfolio last night. Well, I think your share price reflects that. Thank you, as it ticks a lot of boxes on inventory depth, cash breakevens, and free cash flow capacity, allowing the market to value your company. So thanks to whoever had the initiative to do that—it’s brilliant. That's my first general comment. I have two questions. The first one would be on Slide 7. Can you provide some commodity benchmarks around your ranges to help bookend what’s happening on the inventory? That's my first question.

When you say commodity benchmarks, are you referring to the inventory ranges we provided on the slide?

Yes, the inventory ranges you've given, Tom. Can you explain that?

Yes, absolutely. We have considerable robustness in our inventory. We typically evaluate our inventory at various price points. I have a permutation in front of me that's run at $60 oil and $3 gas, and another at $85 oil and $4.25 gas over the long term. I must note that at $3 or less, we assume some reduction in capital. For the $60 oil and $3 gas scenario, we would reduce current capital expenditures to 70%. However, at the $85 and $4.25 mark, that's at the current cost structure. Depending on how you define a 1.25 PVI10 hurdle, we find that at $60 and $3, 75% of our total inventory would meet that criterion. Conversely, at $85 and $4.25, 91% of our inventory would hurdle at that threshold. This demonstrates we maintain a solid downside protection on our inventory.

Great color. Thanks, Tom. I appreciate that. I guess my follow-up, I wanted to ask about the slight change in messaging regarding share buybacks. I think you all know our view on variable dividends for a depleting business with finite resources. It seems that you guys are pivoting to recognize the inherent value in your stock. Can you walk us through the investor feedback that influenced your decision to make that shift?

We've received mixed signals from our investor base. While some prefer one direction, others favor another. We've monitored the market response to the variable dividend closely, and that's been a strong signal indicating what the market prefers. We're receptive to constructive criticism, and we aim to improve and adopt best practices. We believe that long-term buyback strategies represent not only a favorable investment opportunity but also an accretive move for our long-term owners. This decision to adjust our priorities wasn’t made lightly, but we’re confident it’s the right choice for 2023.

Thanks, guys.

Your next question is from David Deckelbaum of Cowen. Please go ahead. Your line is open.

Good morning, Tom and Scott. Thanks for taking my questions today.

Hi, David.

Hello. If I could just dive into the upper Marcellus a little bit to enhance my understanding. This year, it sounds like the mix is going to be higher relative to the overall upper versus lower mix in the next few years. I’m curious about how much of the resource you think will be derisked this year, and how many of those locations will be near areas where the lower Marcellus has been depleted?

While I don’t have the precise number for how much we’ll derisk, we are careful to space our upper Marcellus pads across our assets, developing a solid understanding of how much will ultimately be developed. It's worth mentioning that there's substantial drilling in the upper Marcellus. Currently, we are experimenting with longer lateral lengths, well spacing, and varying completion designs to see how they behave when we position wells adjacent to one another. Thus far, we’re positive about the results, and it hasn't changed our perspective regarding the asset. We still have considerable lower Marcellus resources available and will pivot back to it, largely influenced by our infrastructure availability.

Thanks, Tom. And my follow-up: does the ramp up to 100 million a day in the next couple of years assume similar activities in the Marcellus? Is the implication that having more of the lower will contribute to better infrastructure availability?

Yes, achieving the target mentioned reflects the outcome of the projects we're drilling, the timing of completions, and what we expect those to deliver. It’s also driven by the additional investments we're making this year, which we anticipate will yield positive results in the following two years. Some of this involves insights from previous years’ efforts.

Good morning, Tom and team, and congrats on a strong year-end.

Thank you.

For my first question, I wanted to focus on your 2023 capital program. If we assume a flat commodity price environment, how do you expect service costs to change across your operations? More broadly, where are you seeing the greatest headwinds and tailwinds from a service cost perspective?

Yes, Derrick. It's challenging to pin down service costs to commodity prices. It’s ultimately a function of activity levels and service availability in the market. I'm pleased to say we've noticed some softening lately, particularly in rig rates, and that’s a positive sign. We've seen a decrease in casing costs, our OCTG, that are expected to decline over the next three to six months. We're beginning to see some price reductions, which is a good sign. However, it will depend on overall activity trends across the lower 48. All rigs and crews have mobility, and we'll monitor how that unfolds.

That’s terrific. As for my follow-up, I’d like to shift to the Anadarko. Your well results on Slide 17 and 18 seem to indicate a call for higher capital investment, especially in the updip part of the play. Would you be able to provide updates on the design and spacing at Leota/Clark?

Yes, regarding Leota/Clark, our design improvements stem from extensive work we've done over the years. We did space those wells a bit further apart. We also learned to position our wells some distance from parent wells, and we’re very pleased with the outcomes. Looking ahead in our three-year plan, the Anadarko has several promising projects this year. We will then take a brief hiatus before resuming in January 2024 with increased activity. Observing the inventory slide, these high-quality locations demand more capital investment and pose a challenge, but in a good way, for our plans. Our team has generated several attractive project proposals, and we are working to manage the potential to their advantage.

Good morning, everyone.

Hi, Matt.

To tease out a consistent theme, there’s growing interest from the broader market regarding capital allocation in gas production. I wanted to circle back to your mid-cycle gas price of $2.75. If this scenario plays out, could you provide insight into Marcellus capital allocation heading into 2024? As you know, you prioritize returns, and even at a $3.50 range, the Permian still offers better overall returns compared to the Marcellus from your presentations. Would there be flexibility in the program in light of potential cost structure once service contracts are resolved if the mid-cycle price of $2.75 becomes a reality?

If $2.75 is the price point, it’s something we'll seriously evaluate. Our current plan maintains a largely flat activity level in the Marcellus, and we intend to proceed as scheduled. However, if the oil-to-gas ratio shifts and we find better returns elsewhere, we will pivot accordingly based on that analysis. Last year's oil-to-gas ratio was approximately 10 to 1. Currently, it’s around 30 to 1. With mid-cycle pricing considered, we've adopted a focused and patient approach to decision-making.

That makes sense. As a follow-up regarding the Marcellus, I understand you've discussed the frac barrier and developed zones without co-development. Can you offer insights regarding the program for the upper Marcellus? I know you mentioned 40% for this year. Over the three-year outlook, what might be the anticipated percentage of upper Marcellus wells in the program for 2024 and 2025?

For our three-year plan, the upper Marcellus will have a larger percentage this year compared to prior projections. In the subsequent years, 2024 and 2025, the upper Marcellus will represent approximately 30% to 40% of our total program. Additionally, we reaffirm our stance that the frac barrier indeed allows hydraulic isolation between the two units, providing us with the ability to stage development most judiciously.

Good morning. Thanks for accommodating me. My first question is about your Permian project sizes. It appears that now 8 to 10 well pads are considered optimal. Could you explain what has driven this trend, such as cost efficiencies?

The 8 to 10 well project size evolved through practical operational considerations. Reviewing cycle times and facility design, this approach proved viable. The Delaware basin operates distinctly relative to other basins. For example, we have a single pad in the Delaware producing over 100,000 barrels of water per day. Therefore, project sizes and pad designs in the Delaware arise from varying infrastructure requirements.

The number of wells per pad stems from a continuous effort to enhance efficiency. Our teams constantly seek to maximize efficiency and cost savings. Higher well counts per pad ultimately lower cost per well, optimizing spending. Currently, we have pads with wells extending both north and south, allowing us to return for additional extractions following significant water flowbacks.

I want to clarify that our single project is producing 100,000 barrels of water per day, not oil. In the Marcellus, we produce approximately 5,000 barrels per day across the entire field.

That's substantial. Thank you for that clarification. Regarding your Marcellus delineation plan, you mentioned that roughly 40% of the plan will focus on delineation. Is this plan broad enough to cover most of the area, or are there some specific key areas you’ll be focusing on? While I know you won’t provide guidance for 2024, is this delineation trend expected to continue at that percentage into next year?

We’re focused on a comprehensive delineation across the upper Marcellus. This strategy is influenced by takeaway capacity and infrastructure needs. Our approach involves careful planning regarding where to bring production on. You'll see this theme in the upper areas as we move forward, with exact locations influenced by infrastructure considerations.

Looking at the map of our upper Marcellus projects, there's a good distribution across our acreage. We believe you will be pleased with our delineation strategy. It's essential to remember that infrastructure plays a critical role in our plans. We will open a new compressor station in the Marcellus in the next year or two, which will enhance our prospects for further expansion.

Hi. Good morning. I'd like to get some clarity on how you plan to execute the share buybacks. Will there be a set amount each quarter based on free cash flow, or will you approach it opportunistically based on your internal NAV?

We will indeed focus primarily on internal valuations but will prioritize opportunistic buying. We still seek to return capital to shareholders, similar to what we did with the previous program. We'll look at the marketplace to evaluate how our stock is trading against our assessment of its true value. We have a commitment to this buyback, but we will not be rigid; we will act opportunistically.

Thank you. A follow-up regarding the multi-year outlook. What would you identify as the main driver behind increased oil production? Certainly, you’ll add more wells, but is there a productivity change or a focus on more productive areas influencing this growth?

The primary driver is the additional capital we’re investing this year. We’re positioning ourselves for the upcoming year, and we're excited about the prospects. Our assets across Delaware are promising, and due to favorable oil prices, it makes strategic sense to focus our investments here.

Hi, guys. I wanted to ask about your CapEx outlook. You’ve discussed a range between $2 billion and $2.2 billion this year. Can you provide context around what would push you toward the higher or lower end? I'm presuming that may relate to service costs. As I review the three-year outlook, it appears you're projecting a slight decrease to around $2.0 billion to $2.1 billion in the following years. What are the considerations for that decline? Is there an expectation that service costs may moderate?

The 2023 program is modeled at current costs, which might push us just slightly above the midpoint. The 2020 to 2021 range is primarily driven by asset mix and project selection variances. Some asset regions have higher dollar-per-foot costs while others are lower, with changes alternating through the three-year program.

That's helpful. Additionally, regarding the variable dividend compared to buybacks, can we expect a scenario this year with minimal variable dividends while boosting buyback significantly, particularly given the stock's decline from last year's highs?

Yes, that’s a reasonable assumption. Our current priority is the base dividend first, followed by buybacks, and any potential variable dividends if needed. Considering the recent pressuring on our stock, it’s clear we see great opportunities in this area.

Hi. Good morning.

Good morning.

Two questions, please. My first question regards the buyback and fixed dividend. Assuming that later this year, you raise your cash balance to $1 billion, should we assume that any excess cash will be directed entirely towards shareholder returns? Does this imply that if you exceed the 50% level, you may also want to further strengthen your balance sheet?

The allocation is not governed by a fixed formula. While we target a $1 billion cash balance, our minimum commitment remains 50% of cash flow. We have the flexibility to return additional funds as needed based on market conditions, so the target is not strictly determining how we allocate above $1 billion. Our current priorities involve ensuring we maintain that $1 billion cash target while effectively executing buybacks and distributions as opportunities arise.

Regarding inventory, having a long-term inventory allows us to run our business with financial and operational clarity without panic over short-term challenges. We truly appreciate our good fortune, having a deep inventory. We'll continue to explore bolt-on acquisitions that you’ve mentioned, but M&A can be risky territory. We must possess some advantages—financial, operational, or locational—when considering acquisitions so that we don't overextend ourselves. We aim to be opportunistic; however, our substantial inventory allows us more time to strategize.

Good morning, Tom and Scott. I have a further question about the buybacks. Considering the current environment, it seems you’re heavily leaning towards buybacks at the moment. Do you anticipate this shift will endure over time and across price levels? If so, how would you gauge the sustainability of this approach?

I wouldn't provide a definitive price point, but it is safe to say that this shift reflects a more durable strategy given our understanding of buying back stock's lasting effects across cycles. The financial aspects remain compelling, and I have often contemplated what my share count would look like had I utilized variable dividend money instead of buybacks last year. This thought process is quite intriguing. While I can’t guarantee a lock-in approach, I firmly believe our buyback strategy is beneficial long-term. We will also remain agile to respond to market changes.

Furthermore, we're making decisions reservation by reservation on how we handle our capital return. We’ll continue to communicate openly with investors regarding our priorities. We are devoted to delivering shareholder value efficiently while maintaining operational agility.

We have completed the allotted time for questions. I will now turn the call back over to Tom Jorden for closing remarks.

Thank you all for joining us. We look forward to executing our plans, demonstrating our commitment, and delivering on our promises. Thank you once again.

This concludes today's conference call. Thank you for your participation. You may now disconnect.