Coterra Energy Inc. (NYSE:CTRA) Q4 2022 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q4 2022 Earnings Call Transcript February 23, 2023

Operator: 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 speakers’ remarks, there will be a question-and-answer session. . Thank you. Dan Guffey, Vice President, Finance, Planning and Analysis and Investor Relations, you may begin your conference.

Dan Guffey: 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 Web site. With that, I’ll turn the call over to Tom.

Tom Jorden: 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 performance, outlook for 2023, three-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, 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 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 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 can 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. Furthermore, 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. 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 projects our current cost structure. As Slide 6 in our investor deck shows, we have an active plan that generates an annual average 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 in each of the next three years on average. 2023 is year one of this multi-year plan. Basically the 2023 plan that 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 have significant impact on 2024 and beyond.

Furthermore, we have optionality. The 2023 capital plan of 2.0 billion to 2.2 billion has off ramps in the event conditions were to significantly degrade. We have balanced our program with some services under our 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 costs of supply with our Marcellus gas assets. And 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 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 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 have built a multi-year plan that invest through the cycles generates modest profitable growth, and checks the box for ability to withstand further commodity price erosion. The ability to confidently invest in 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 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 than 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 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.

Scott Schroeder: Thanks, Tom. Today, I will discuss our fourth quarter and full year 2022 results, shareholder return strategy, and then finish with our ’23 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 ’22 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, 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 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 ’22, 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 is 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% plus 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 hit our minimum threshold.

Lastly, I will discuss the 2023 outlook. The company’s 2023 capital is estimated to be $2.0 billion to $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. 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 fallen from a $6 annual average to a recent strip of $3. However, front month prices are near $2.16 and this 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 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 going to the Anadarko.

On the heels of 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 is above the 30% to 40% range we discussed as a preliminary target in late ’22. This range is likely to be the higher end of the range for the upper Marcellus versus the lower Marcellus split over the three-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 dollar per BOE unit costs are flat to down across the board largely driven by lower commodity prices outlook. Lastly, the future of Coterra is bright. Based on the current service cost environment, we estimate that if a 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 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 plan production, expenses and far exceeded revenues due to a small hedge book and robust pricing. For ’23, 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.

Q&A Session

Operator: . Please limit yourself to two questions. Your first question is from Nitin Kumar of Mizuho. Please go ahead. Your line is open.

Nitin Kumar: 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. So 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?

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

Blake Sirgo: Yes. Thanks, Nitin. Our ’23 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 per year over the next three years. What that does for us is provide 0% to 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. But 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.

Nitin Kumar: 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?

Scott Schroeder: Actually, Nitin, I’ll give that to Blake. He’s over our marketing group now.

Blake Sirgo: Yes. Thanks, Nitin. There’s a couple of 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, but it’s also our portfolio. We have more contracts in ’23 pointed at premium markets than we did in ’22. We also have a good chunk of our portfolio that has floors under them. And at these lower prices, those floors come into play. So it’s really just overall great work by our marketing team. It’s a really good tailwind in the U.S. going into ’23.

Nitin Kumar: Great. Thanks, guys.

Operator: Your next question is from Umang Choudhary of Goldman Sachs. Please go ahead. Your line is open.

Umang Choudhary: Hi. Good morning. And thank you for taking my questions. I 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?

Scott Schroeder: Sure. What we found in this past year is as we looked at, we set out to do about $1.5 billion in variable dividends. And 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 ourselves because we think our assets are head and shoulders above everybody. And so leaning in on the buyback as that return of capital priority, but also increasing the base is what we have telegraphed over the years too that we’re going to continue to do annual base dividend increases. So 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. So 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.

Umang Choudhary: That’s very helpful. Thank you. And then maybe to follow up on Nitin’s questions on flexibility of your capital program to changing macro conditions, what kind of flex do you have in your program over the next three years? And then any color you can provide on the recent cost trends will be helpful. Thank you.

Tom Jorden: Well, I’ll handle the first part and Blake can talk about cost trends. We have tremendous flexibility. 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. And we — our operations team worked really hard to give us flexibility. So we have some services under annual contract and some that we have the option quarter-to-quarter. Now the longest term we have is an annual contract. So if you look out at the three-year program, we have tremendous flexibility. But 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.

Blake Sirgo: Yes. And on the cost trends, the 10% we’re showing for ’23 is really a reflection of those contracts we entered into in late ’22. It sure feels like the market is starting to soften. There’s less talk about price increases, or talk about costs holding flat. And if activity starts to drop across the lower 48, we’ll be looking to claw some of those costs back.

Umang Choudhary: Very helpful. Thank you, guys.

Operator: Your next question is from Arun Jayaram of JPMorgan. Please go ahead. Your line is open.

Arun Jayaram: 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. And 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, call it, wells tied to sales, or do you have increases baked in to deliver call it high-single digits oil growth in ’24 and ’25 based on this outlook?

Tom Jorden: Yes, 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. So I think you could really see a level set in terms of the ’23 activity going forward. But just an editorial comment, Arun. 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, the operational cadence. And quite frankly, I think as an industry, we’ve typically kind of gotten that exactly wrong in terms of when we invest and what we can track. So 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.

And that’s what we’re going to do. And that’s a strategic pivot for us. It’s why we put Coterra together. Now whether that operational cadence has our current rig count or a rig count less or a rig higher, we’re going to 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.

Arun Jayaram: 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 some thoughts. Well productivity has been a concern from the buy side, including from one of your partners in Culberson County who highlighted that on their call, but what are your thoughts on sustaining this level of well productivity in the Delaware on a go-forward basis? And how does the Harkey Shale kind of fit into that overall development scheme?

Tom Jorden: We do not see a change in our Delaware productivity. 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. And I’m talking about projects with over 10 wells that average 1,000s of barrels a day. So those are you — we don’t have tons of those and we drilled a couple of them in ’22 and that was part of that productivity in ’22. But 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. But we do not see that as a factor that degrades overall well productivity.

We typically stage that development within reasonable proximity of time. But 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. So we don’t see that as a significant issue for the Wolfcamp, Harkey. And I think the big answer to your big question is, over that three-year landscape, we don’t see significant change in our Delaware productivity.

Arun Jayaram: Great. Thanks a lot, Tom.

Operator: Your next question is from Jeanine Wai of Barclays. Please go ahead. Your line is open.

Jeanine Wai: Hi. Good morning. Thanks for taking our questions.

Tom Jorden: Hi, Jeanine.

Jeanine Wai: Hi. Good morning. Our first question maybe a macro question kind of following up on Umang’s question about capital allocation. So 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. But now at what point do you really start to rethink capital allocation?

Tom Jorden: Well, look, mid cycle is kind of in the beholder. Everybody says the word mid cycle. And we’d rather you didn’t ask us what the number was. But you do and we’ll answer it. Our current mid cycle is our walking around numbers, 275 natural gas and our assets are really, really robust 275 natural gas. But as we said, Jeanine, we have the ability to move it around. 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 byproduct. So it’s not really a function of a gas price. But right now, our returns are pretty good across our portfolio.

Jeanine Wai: Okay, great. Thank you. And then maybe just following up to Arun’s question on the three-year plan, oil is expected to grow at 5%, gas anywhere between 0% and 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. But what really determines in the three-year plan where gas kind of lands in that range, 0% to 5%? I think you addressed 2023 really well. We’re thinking, for example, it seems like Marcellus productivity per foot is getting worse this year. But ’24, ’25 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.

Tom Jorden: Well, we are kind of in a shoulder period natural gas right now, outlook on natural gas. In 2024, we’ll have LNG export come online. And so 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. We’re in the mid 40s on upper Marcellus this year on a total footage. And we’ve talked openly that the upper Marcellus doesn’t have the productivity per foot of the lower Marcellus. That’s something that’s a fact of our assets; still outstanding, still very good and we’re going to continue to develop it as we go.

Jeanine Wai: All right, great. Thank you, Tom.

Operator: Your next question is from Doug Leggate of Bank of America. Please go ahead. Your line is open.

Doug Leggate: 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, basically allows the market to value your company. So thanks to whoever had the initiative to do that is brilliant. So thanks for that. That’s my first just general comment. I’ve got two questions the information is never enough. So I guess like the first one would be on Slide 7. Can you give us some commodity benchmarks around your ranges just so we can bookend what’s going on, on Slide 7 on the inventory? That’s my first one?

Tom Jorden: When you say commodity benchmarks —

Doug Leggate: The inventory ranges you’ve given, Tom, are —

Tom Jorden: Yes, 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 $4.25 gas long term. Now I will say when we go to $3 or less, we do assume some reduction in capital. And currently, we say, all right, if we’re going to say $60 oil, $3 gas, we’re going to take 70% of current capital expenditures. But the $85, $4.25 is at current costs. And so 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 cut off, we’ve been using 1.5 in one of our disclosure, but I’m going to give you 1.25.

At $60 and $3, 75% of our total inventory would hurdle at a 1.25 PVI10. And at $85 and $4.25, 91% of our inventory would hurdle at a 1.25 PVI10. And again, at $85, $4.25, that is the current cost. So we have a fair amount of downside protection on this inventory.

Doug Leggate: Great color. Thanks, Tom. I appreciate that. I guess my follow up is I really just wanted to ask you — 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 . I won’t get on my tool box , but it seems that you guys are pivoting to recognize that there probably is some value in your stock here. So can you walk us through the investor feedback that you I think is how you described part of your decision to make that shift? And I’ll leave it there. Thanks.

Tom Jorden: Well, Doug, we’ve heard very mixed signals out of our investor base. 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 is looking for. And then we listen to our critics, and we think about it and we really do have an honest attempt to get better and adopt the best approach. And 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. And so 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.

Doug Leggate: Again, I appreciate the color, guys. Thanks very much indeed. And congrats on all your new disclosure.

Tom Jorden: Thanks, Doug.

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

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

Tom Jorden: Hi, David.

David Deckelbaum: Hello. If I could just dive into the upper Marcellus a little bit just from my — 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. So 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 derisking this year relative to what you have sort of envisioned overall? And then how many of those locations are going to be in areas where the lower Marcellus has already been depleted?

Tom Jorden: Well, I don’t have the answer at my fingertips as far as what we’re going to derisk. 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. 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. And 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 we’ll be pivoting back to it. That’s more a function of our infrastructure availability, and we’re trying to manage that so that we keep our line pressures reasonable and we don’t overdrive the system.

David Deckelbaum: Thanks, Tom. And 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. So is that just reflecting a quality mix between having more of the lower and perhaps just better infrastructure availability?

Tom Jorden: Yes, I’m not following your 100 million a day, David?

David Deckelbaum: Sorry. I thought that I saw in your presentation that the implication was that you would get, call it, from 3.8 to 3.9 .

Tom Jorden: Yes, I see what you’re saying. No, that’s — look, we would love to get our natural gas back on our growth profile and that’s just now come 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 will deliver. 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. So some of that’s just fruits of seeds we’re planting this year.

David Deckelbaum: All right. Best of luck with the garden. Thanks, Tom.

Tom Jorden: Thank you.

Operator: Your next question is from Derrick Whitfield of Stifel. Please go ahead. Your line is open.

Derrick Whitfield: Good morning, Tom and team and congrats on a strong year end.

Tom Jorden: Thank you.

Derrick Whitfield: For my first question, I wanted to focus on your 2023 capital program. If we were to assume a flat commodity price environment, how would you expect service cost to change across your operating areas? And then more broadly, where are you seeing the greatest headwinds and tailwinds from a service cost component perspective?

Blake Sirgo: Yes, Derrick, this is Blake. I’ll take that one. It’s hard to pin a service cost to a commodity price. It’s really ultimately a function of activity and how much services are available on the market. We’re seeing some softening. 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. But ultimately, it’s going to be a function of activity across the lower 48. All rigs and crews have wheels and they will travel. So we’ll see where activity goes.

Derrick Whitfield: Terrific. As for my follow up, maybe shifting over to the Anadarko. Your well results on Slide 17 and 18 seemingly beg for higher capital, particularly in the updip part of the play. Could you perhaps speak to the updates you’ve integrated in your design and spacing at Leota/Clark?

Tom Jorden: Yes. Specifically, Leota/Clark was an outgrowth of a lot of work we’ve done over the years. We did space those wells a little further apart. One of the things we also learned is to put our wells a little further away from parent wells, and very, very pleased with the results. As we look ahead in our three-year plan, the Anadarko has a few very, very nice projects this year, and then we take a little pause and then we start up January 1 of ’24 with additional activity. But as you look at that inventory slide, these are high quality locations really begging for more capital, quite frankly. And the team is making it really hard for us. And as we asked them to do, they’ve come forward with some really, really nice projects in inventory. And we’re just in the progress of trying to manage and embarrass from the riches.

Derrick Whitfield: Terrific. Thanks for your time and color.

Operator: Your next question is from Matt Portillo of TPH. Please go ahead. Your line is open.

Matt Portillo: Good morning, all.

Tom Jorden: Hi, Matt.

Matt Portillo: Just to tease out on kind of a consistent thread here, Tom. There’s obviously a lot of interest from the broader market and gas capital allocation. So I 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. So just curious if there’s some flexibility in the program once you get through your service contracts, where the Marcellus may receive a little bit of — a little less capital in 2024 if that 2.75 mid cycle price plays out?

Tom Jorden: Well, if 2.75 were the price, I think that’s probably something we’d look at seriously. Our current plan has fairly flat level of activity in the Marcellus and our intention is to solider on. But if we look very carefully at the oil/gas ratio and the return differential, and we’re going to pivot and try to find the best returns within our portfolio. The oil/gas ratio last year was 10 to 1. It’s currently 30 to 1. And we talked about mid cycle pricing. That mid cycle ratio is really what we’re looking at. And we don’t want to react — we don’t want to kneejerk near term. We’ve got the wherewithal to be patient on this.

Matt Portillo: That makes sense. And then just a follow up to the Marcellus. I know you guys have talked about the frac barrier and the ability to develop 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 ’24 and ’25?

Tom Jorden: Yes, in that three-year plan, the upper Marcellus is the highest percentage this year that we’re currently projecting over the next three years. But in the out years, ’24 and ’25 and our current plan is the upper Marcellus is going to be about 30% to 40% of our total program. And 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.

Matt Portillo: Thanks so much.

Operator: Your next question is from Neal Dingmann of Truist Securities. Please go ahead. Your line is open.

Neal Dingmann: Good morning. Thanks for squeezing me in. My first question, Tom, for you again is just on your Permian project size. And specifically, I was looking at that slide it looks like now. What would you consider or would you consider kind of the 8 to 10 well pads now as the most optimal and was wondering does that increase due to sort of just overall cost out there efficiencies or what has driven these larger project development?

Tom Jorden: Well, I’ll chime in and then Blake will come in as well. That 8 to 10 well project size, we didn’t come up with that through some deep thinking. It kind of just happened operationally as we look at cycle times. We look at facility design that seemed to be what looked to work. The 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, a single project. And so pad design in the Delaware is a function of a lot of things, one of which is infrastructure.

Blake Sirgo: Yes, I’ll just tack on. 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 combing we can do. It just drops our per well cost, our dollar per foot cost. Our teams have got really creative. 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 added new zones and plug those into the same facilities. Probably our biggest limit is just kick-outs 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 going to squeeze on one pad.

Tom Jorden: Neal, I want to correct myself that projects and pads or one pad is producing 100,000 barrels a day. I said — I was talking about project. One pad is producing 100,000 barrels a water a day.

Neal Dingmann: Either way, that’s big. That’s great clarification. That’s great.

Tom Jorden: In Marcellus, we produced 5,000 barrels a day in the whole field.

Neal Dingmann: All right. And then my second question is on your Marcellus delineation plan specifically. I saw in the release you all mentioned about 40% of the Marcellus plan is delineation in nature. Is this plan going to cover most of the broader position, or are there some key areas that you’re delineating? And then I know you’re not going to give ’24 guide, I’m not looking for that, but will that delineation continue to that percent as well into next year as well?

Blake Sirgo: This year, 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. We’re careful where we bring that on. And 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.

Tom Jorden: Yes. Neal, I’m looking at the map right now of our upper Marcellus projects, it’s a pretty good scattershot over our acreage. So I think you’ll all be pleased with our delineation. I also want to remind everybody that infrastructure is 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.

Neal Dingmann: That’s a great answer. I look forward to hearing all the details. Thanks, Tom.

Operator: Your next question is from Kevin MacCurdy of Pickering Energy Partners. Please go ahead. Your line is open.

Kevin MacCurdy: Hi. Good morning. I was wondering if you could 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 going to be more opportunistic based on your internal NAV?

Scott Schroeder: We’re going to, obviously based on, like you said, the internal evaluations do, but we’re going to continue to — just like we did with the last one, be more — 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, but we’re not going to become programmatic in doing it. So it will still be more opportunistic than anything else.

Kevin MacCurdy: Great. And then just, if I can, a question on the multi-year outlook. What would you say is the main driver of the increased oil production? Obviously, you’re going to put on more wells, but are there any changes in productivity, drilling in more productive areas or higher working interest areas that are contributing to that impressive growth?

Tom Jorden: 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. But look, we love our Delaware assets. We love all of our assets. And because of oil prices, it just makes sense to put that little extra effort forward this year and reap the rewards.

Kevin MacCurdy: Great. Thank you for taking my questions.

Operator: Your next question is from Leo Mariani of Roth/MKM. Please go ahead. Your line is open.

Leo Mariani: Hi, guys. I just wanted to ask a little bit about the CapEx outlook here. So you guys are talking about 2 billion to 2.2 billion 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. And then as I look at the three-year outlook, you guys are expecting that to come in slightly to kind of more 2.0 billion to 2.1 billion in the next couple of years. So just wanted to get a sense of why that’s coming down a little bit. Is there any expectation that service costs might come in? Obviously, you talked about some of the trends maybe starting to look favorable.

Blake Sirgo: Yes. Leo, this is Blake. I’ll take that one. The ’23 program is all modeled at current costs and that would put us maybe just a little north of the midpoint, not assuming any deflation right now. So we’ll see where that goes. The 2 billion to 2.1 billion going out in the next three 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 three-year program.

Leo Mariani: Okay, that’s helpful. And then just wanted to follow up on some of the comments you guys made about the variable dividend versus the buyback. Just wanted to get a sense, I know you guys are going to continuously monitor this, but can we have an outcome this year where we get very, very little variable dividend and the buyback increases rather significantly versus kind of where it had been in the second half of 2022. Obviously, the stock while it’s doing well today has come in quite a bit off the highs from last year or so. Just trying to get a sense if you guys are really going to kind of lean pretty hard on the buyback this year and do kind of very little on the variable dividend depending on how things play out?

Blake Sirgo: Leo, I think that’s a good assumption. The priority that we said is the base first, buyback second and then fill in, if needed, with the variable dividend. So to the core of your question, we’re focused particularly — as we agree with you, our stock has come in quite a bit and we see a great opportunity in that. So if you press me today, I would say your answer is — the direction you’re going is correct.

Leo Mariani: Okay. I appreciate it, guys. Thanks.

Operator: Your next question is from Paul Cheng of Scotiabank. Please go ahead. Your line is open.

Paul Cheng: Hi. Good morning.

Tom Jorden: Good morning.

Paul Cheng: 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. And 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 which that level that you may want to further strengthen your balance sheet. So trying to understand that once you reach that level, what kind of distribution that we should assume? Secondly, Tom, can you talk about — you have a pretty huge inventory backlog already. So 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 assets? Thank you.

Blake Sirgo: 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% plus. As we just highlighted, we returned 83%. So 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% plus 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. So you can’t pinpoint to something that once we get to this point, we’re going to 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% plus base dividend and buyback first, and we’d like to get our cash balance up because what the cash balance does, being a little bit higher, affords us flexibility in the question that you’re asking, Tom.

Tom Jorden: And I’ll take that question. 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 handle our operational teams. We’re very proud of our operational teams and their ability to integrate, operate smartly and really bring a hidden value forward. We’re going to constantly look.

But M&A is a perilous territory. When you typically want to have some advantage, that advantage can be information advantage, it can be operational advantage, it could be geographic advantage. But we’re probably not going to be showing up to auctions and trying to outbid people that have the same information we do. So we’ll be opportunistic, but we’re blessed with the luxury of not having to do something, and that’s a nice place to be.

Operator: Your next question is from Charles Meade of Johnson Rice. Please go ahead. Your line is open.

Charles Meade: Good morning, Tom and Scott. 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. And Scott, I know this is a conversation that you engage in 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. And if you are thinking about it as a durable pivot, maybe you can share kind of up to what price you view it as being durable?

Scott Schroeder: Well, Charles, that’s a nice try. I won’t give . But 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. 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? And that number kind of intrigues me. Now can’t undo what we did last year. So I think where you’re leaning is I view this as more durable because it is I think the best long-term solution. Now there will be points and disconnects in the market where it may not make sense. But 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.

Tom Jorden: But we are also going to make the best decision quarter-by-quarter and be prepared to pivot. We’re not making some wholly 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.

Charles Meade: Got it, Tom. And Scott, that’s good for me. Thank you.

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

Tom Jorden: Thank you all for joining us. We look forward to executing, showing you that we’re doing what we believe, and we’re going to deliver what we promise. So thank you all very much.

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