Coterra Energy Inc. (NYSE:CTRA) Q2 2024 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q2 2024 Earnings Call Transcript August 2, 2024

Operator: Hello! Good morning, and welcome to the Coterra Energy 2024 Earnings Call. At this time, all participants are in a listen-only mode until the question-and-answer session at the end of today’s conference. I will now turn the call over to Dan Guffey, Vice President in Finance, Investor Relations and Treasury.

Dan Guffey : Thank you, operator. Good morning, and thank you for joining Coterra Energy’s second quarter 2024 earnings conference call. Today’s prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Blake Sirgo, Senior Vice President of Operations. 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.

Tom Jorden : Thank you, Dan. Thank you to all that are joining us this morning. We’re pleased to discuss our second quarter results with you this morning. Coterra had an excellent second quarter. We delivered strong financial results and a robust return of capital to our owners. We beat production guidance on all three streams. Oil, natural gas, and natural gas liquids, came in on the low end of our capital guidance range, and delivered capital efficiency that demonstrates the quality of our assets and our organization. Shane and Blake will walk you through the details of our quarterly results and updated guidance. I would like to make a few comments regarding our positioning in the marketplace, gas, macro outlook, and perspectives on M&A.

First, we’ve never felt better about our portfolio of assets. Coterra is uniquely positioned in the marketplace. Although we saw a 42% drop in realized natural gas prices between Q1 and Q2 2024, our revenue only declined a modest 12%. This financial resiliency affords us the opportunity to make sustained long-term capital allocation decisions without being buffeted by short-term commodity swings. In a cyclic business, flexibility is the coin of the realm. The combination of our balanced revenue stream, as well as our geographic and geologic diversity, gives us market flexibility. Additionally, our inventory depth and lack of long-term service contracts affords us the luxury to focus solely on the best capital allocation decisions. We can pivot between the Marcellus, the Anadarko, and the Permian as conditions and opportunities warrant.

Next, a few thoughts on the gas macro. Simply put, gas markets are oversupplied. After bottoming out near 97 Bcf per day in May, U.S. natural gas production has rebounded to over 102 Bcf per day. This increase has come primarily from the Marcellus and the Permian, with the Marcellus contributing the lion’s share. Although natural gas power demand has steadily increased over the past four years, largely driven by the retirement of coal-fired generation, a mild winter and inconsistent run time in LNG facilities have contributed to a near-term oversupply. Northeast storage is trending at or near the five-year max. Although we remain bullish on gas long-term, near-term supply-demand dynamics are placing downward pressure on natural gas prices and likely will continue to do so throughout the remainder of injection season.

To that end, we have made the decision to curtail production once again in the third quarter. Additionally, we are exploring the option of delaying upcoming Marcellus turn-in lines and curtailing planned drilling and completion activity. We do not expect any of these decisions to materially impact our 2024 cash flow. These curtailments of potential capital changes are tactical responses to a temporary situation. Our capital allocation decisions are not made in response to fluctuations in the near-term strip. They are in response to macro market conditions. We have plans in place to rapidly restore or curtail activity in response to these changing macro conditions. With increasing LNG exports and growing natural gas power demand, we have a line of sight to a materially better natural gas market.

Our industry does not need $5 gas to have a healthy runway. We do, however, need sustainable price support in the mid-$3s or better to motivate producers to bring incremental gas to market to meet growing demand. We remain ready and willing to do our part. When natural gas prices recover, and they will recover, Coterra is nicely positioned with significant exposure to the upside. Drilling and completion dollars are far and away the most significant expenditures we make. Rather than just curtailing existing production, the biggest impact on Coterra in responding to an oversupplied market will come from delaying or deferring drilling and completion investments. Remember, we do not manage Coterra around production goals. Production is an outcome of sound investment decisions.

Our existing production is the consequence of yesterday’s capital allocation decisions. We believe that it is never wise to make poor investment decisions to maintain or increase production, nor to assign any of our business units a budget that is there, “fair share of capital”. Today’s decisions should be based upon today’s reality. At current commodity prices, much of the Marcellus does not compete with other opportunities in our portfolio. Our core mission is to allocate capital prudently and prioritize our most profitable programs. The most profitable long-term Coterra will best be built by this disciplined capital allocation. We maintain the option to redirect capital to multiple other opportunities within our portfolio or to reduce capital expenditures.

We remain focused on per share value creation through the cycles. Now, a few thoughts on M&A. Coterra has established a track record of outstanding execution, consistent top-Tier financial returns, and disciplined capital allocation among a diverse portfolio of assets. Adding quality assets to our portfolio would play to our strengths, and we have confidence that our organization would manage them exceptionally well. However, quality assets are only half the equation. The assets must come at a reasonable price, including a margin of safety. Buying assets at discount rates that are at or near our cost of capital at high commodity prices can be a recipe for disaster. Upswings in commodity prices, new technology or new geologic zones can save the purchaser, but disaster waits patiently on the other side.

It will wait for a significant sustained downdraft in commodity prices and strike with lethal precision. Furthermore, disaster loves deals that are measured on single metrics, such as near-term free cash flow. We have seen this movie play out repeatedly in our industry. This is not a commentary on any particular deal, but a reflection on lessons learned through the years. Coterra has a deep and diverse inventory, significant and sufficient scale, and a pristine balance sheet that we will defend vigorously. We would love to add assets to our portfolio, but they must offer a combination of quality and value. We are willing to be patient, disciplined, and counter-cyclical. We are also willing to be lonely. Finally, last night we also released our 2024 sustainability report.

We hope that you will find it to be a readable, fact-based discussion of the tremendous progress we have made, as well as the ongoing challenges we face. We remain committed to operational excellence with emissions reduction as a central tenant. Our organization is focused on this mission from the field to the C-Suite. We are deeply proud of this commitment and of the progress that we have delivered. We strive for an authentic voice when discussing these topics, and we hope you will find that our sustainability report reflects this. With that, I will turn to call over to Shane and Blake, who will provide detail on our quarterly results and outlook. First, let’s hear it from Shane.

Shane Young : Thank you, Tom. Thank you, everyone, for joining us on today’s call. This morning, I will focus my comments on three areas. First, I will summarize the financial highlights from our second quarter results. Then, I will provide production and capital guidance for the third quarter, as well as an update of the full year 2024 guide. Finally, I will provide highlights from the progress of our shareholder returns program. Turning to our strong performance during the second quarter. Second quarter total production averaged 669 MBoepd, with oil averaging 107.2 MBopd and natural gas averaging 2.78 Bcf per day. Oil, natural gas, and BOE production each came in just above the high end of guidance, driven by a combination of a modest acceleration of timing and strong well performance.

In the Permian, we brought online 23 net wells during the quarter, in line with our 23 net well midpoint guidance. In the Marcellus, we brought online 12 previously deferred wells for a few days in June to de-water the development, but they contributed negligible volumes during the quarter, approximately 18 million cubic feet per day, or less than 0.1% of second quarter gas volumes. The higher than expected gas production in the quarter was primarily due to strong base production and outperformance of wells turned in line during the first quarter. We also turned in line 15 net wells in the Anadarko region, just above the high end of our guidance range. During the second quarter, pre-hedge revenues were approximately $1.3 billion, of which 75% was generated by oil and NGL sales.

We reported net income of $220 million or $0.30 per share, and adjusted net income $272 million or $0.37 per share. Total unit cost during the quarter, including LOE, transportation, production taxes, and G&A, totaled $8.35 per BOE, near the midpoint of our annual guidance range of $7.45 to $9.55 per BOE. Cash hedge gains during the quarter totaled $36 million. Incurred capital expenditures in the second quarter were $477 million, near the low end of our guidance range. Lower than expected capital was driven primarily by timing, and we are maintaining our full-year capital guidance. Discretionary cash flow was $725 million, and free cash flow was $246 million after cash capital expenditures of $479 million. Our credit and liquidity ended the quarter very well positioned.

Cash and short-term investments stood at $1.32 billion, $575 million of which will be used to retire notes coming due to September. After this debt retirement, total debt will stand at approximately $2.07 billion. Looking ahead to the remainder of 2024. During the third quarter of 2024, we expect total production to average between 620 to 650 MBoepd. Oil to be between 107.0 and 111.0 MBopd, and natural gas to be between 2.5 and 2.63 Bcf per day. Continued strong execution and well performance is expected to drive oil volume growth of approximately 2% quarter-over-quarter. Third quarter gas production will be impacted by our plan to curtail approximately 275 million cubic feet per day net in the Marcellus for August and September due to low expected in-basin pricing.

This will drive a decline in natural gas volumes quarter-over-quarter, but not have a material impact on our cash flow. We will continue to monitor gas fundamentals closely and retain the optionality to respond to market signals on a month-to-month basis. Regarding investments, we expect total incurred capital during the third quarter to be between $450 million and $530 million. Turning to full year guidance, yesterday we increased our 2024 oil production guidance range to be between 105.5 to 108.5 MBopd for the year, up approximately 2.4% from our May guidance. Despite the shut-ins, we are maintaining our full year 2024 natural gas production guidance at the midpoint. Lastly, we are increasing our 2024 BOE guidance by 5 MBoepd at the midpoint from May.

During the full year 2024, we are reiterating our incurred capital guidance to be between $1.75 billion and $1.95 billion, which is 12% lower at the midpoint than our 2023 capital spend. As previously discussed, our 2024 program modestly increases capital allocation to the liquids rich Permian and Anadarko Basins while decreasing capital by more than 50% in the Marcellus year-over-year. Finally, there are no changes to our 2024 per BOE cost guidance. Moving to shareholder returns. Last night we announced a $0.21 per share base dividend for the second quarter, or annualized at $0.84 per share. This remains one of the highest yielding base dividends of our peers at over 3%. Also during the quarter, Coterra continued to execute on its shareholder return program by repurchasing 5 million shares for $140 million at an average price of approximately $27.72 per share.

In total, we returned $295 million to shareholders during the quarter for 120% of free cash flow. We remain committed to our strategy of returning 50% or more of our annual free cash flow to shareholders through a combination of our healthy base dividend and our share repurchase program. However, in response to low natural gas prices, we have counter cyclically increased our buyback during the first six months of 2024 and have returned over 100% of free cash flow. We continue to see our shares as a highly attractive use of capital. In summary, the team delivered another quarter of high quality results in the field, which resulted in another successful quarter financially for Coterra. Our business carries significant operational momentum into the second half of the year, and we are positioned for a strong finish to 2024.

Moreover, we are on track to meet or exceed our differentiated three-year outlook we laid out back in February. With that, I will hand the call over to Blake to provide details on our operations.

Blake Sirgo: Thanks, Shane. Our team’s had another strong quarter of execution in the field. We continue to see increases in our pace of operations. We are drilling faster, fracking faster, and our well performance is meeting or exceeding expectations. This is leading to shorter cycle times, which is supporting production beats. In the Permian, we are currently running eight drilling rigs and two frack crews. Our plan to bring in a spot crew at the end of the year has evaporated due to the high efficiencies we have realized from both our electric crew and diesel crew operating in the basin. Both crews are achieving record pumping hours per day, which is allowing us to do more with less. However, these gains are accelerating modest amounts of capital into the year.

This capital acceleration is offsetting our cost savings, which is keeping our 2024 capital guide intact. Efficiency gains are also showing up on the cost side of the equation with our 2024 $1 per foot estimated to come in at $1,065 per foot, which is down 11% from our 2023 cost. This 11% reduction is driven by the combination of year-over-year cost inflation and the efficiency gains we have discussed. In Culberson County, our Windham Row project is on track to meet or exceed our plan, both from a timing and cost perspective. To date, we have 21 wells producing, 25 wells completing, and 11 drilling. Thanks to our drilling team’s great performance executing the Row, including a new Culberson record of drilling 6,119 feet of lateral in a day, we were able to add three more Harkey wells to Windham Row.

This brings our project well count to 57 wells, including six Harkey wells, which will be co-developed with the Upper Wolfcamp. Additionally, our team has moved the drilling rig to the eastern side of the Windham Row, where we have begun drilling the 16 remaining Harkey wells that overlay the Wolfcamp. These wells are expected to come online in early 2025. Windham Row and expected future row developments in Culberson are the definition of oil field efficiency on steroids. The combination of our grid-powered rigs and frack fleet, centralized facilities and infrastructure, and the recent addition of simul-frac have lowered our Culberson cost structure 10% to 15% compared to our diesel zipper operations we previously ran in the county. Our simul-frac performance on Windham Row continues to beat our projections, and we see simul-fracing as a new weapon in the holster for Coterra in Culberson County.

In the Marcellus, we are currently running one drilling rig and one frack crew. We have begun completion operations on our Rayias pad, which is the first of three Tier 1 lower Marcellus pads we will be completing from now through the end of October. We currently have no committed completion activity after these three pads. We have been watching northeast gas markets closely and responding to weak gas prices. Last quarter, we delayed 12 TILs due to softness in local gas markets. During the month of July, we brought on those TILs due to favorable pricing we were able to secure. Unfortunately, we were not able to obtain attractive pricing in August. So yesterday, we strategically curtailed 325 million cubic feet per day gross, 275 million cubic feet per day net across the field.

This volume represents the portion of our near-term portfolio, which is exposed to Marcellus in-basin pricing. We continue to monitor northeast pricing and will extend this curtailment as warranted on a month-to-month basis. Furthermore, we are prepared to make further cuts as some of our summer sales commitments roll off in the shoulder season. As you would expect from us, we will continue to make decisions based on economics and value, not volume. In the Anadarko, we are running one drilling rig and recently completed the bulk of our planned 2024 frack activity. Currently, we are flowing back three projects, which are located in liquids-rich portions of our assets. Initial results from these projects look strong, and we look forward to discussing the economics of these projects once we have more production history.

The Anadarko has shown its resiliency in 2024. The program remains competitive despite the headwinds in the natural gas market. Our Anadarko assets proximity to Henry Hub provides us some of the strongest gas realizations in our portfolio. Those realizations, combined with significant liquid contributions from NGLs and condensate, buoy our economics, making the Anadarko an attractive place to invest capital. At Coterra, we strive for operational excellence in every part of our business. We believe in safety over production, being good neighbors where we operate, and improving capital efficiency, all of which drives value creation. Our team lives this culture every day. We focus on execution, delivering on what we promised, and never settling for the status quo.

And with that, I’ll turn it back to Tom.

Tom Jorden : Thank you, Blake. We’ll now take questions. I’m delighted to hear what’s on your mind.

Q&A Session

Operator: All right, we will now move into the question-and-answer session. [Operator Instructions] Our first question comes from the line of Nitin Kumar from Mizuho. Please go ahead.

Nitin Kumar : Good morning, Tom and team. Thanks for taking my questions and congrats on a great quarter. Tom, you and Blake gave a pretty comprehensive overview of Windham Row. Two specific questions around that. One, as you have kind of progressed through that project and have increased wells and simul-frac, any specific learnings that we should expect to be incorporated into your program, not only in row developments, but also in your smaller Permian projects going forward or across your other operating assets? And then I just wanted to check, I think Blake said 10% to 15% cost savings, whereas the slides still say 5% to 15%. So just maybe understanding what has this project done for your costs in the Permian?

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

Blake Sirgo : Yeah Nitin, really what we’ve seen in Windham Row is our simul-frac performance is meeting or exceeding our projections and that was a real question mark for us coming into it. Transition times on a simul-frac crew, is something we have never done before. And so we were all hoping we can hit the same efficiency we’ve seen in our zipper transition times, and we’ve been able to do that and bring that forward. And so, that’s why we’re increasing the amount of wells that we’re simul-fracing on Windham Row. I do see this as something that we will use quite often in Culberson County specifically, because we have the contiguous acreage, we have the high well count per pad that really makes simul-frac work. As far as the other parts of the basin, we’re absolutely looking at it.

There is an economy of scale that you really want to get with the simul-frac crew. You need to be able to line up a whole lot of wells and have a big chunk of activity to tackle. And so we’re looking where we can to use this even more.

Nitin Kumar : Got it. And on the cost savings, is it returning to the higher end of that 5% to 15% range?

Tom Jorden: Yeah, specifically when we’re talking about the Windham Row savings, and it’s a good market for future rows, we are turning to the higher end of that range, and that’s why I quoted 10% to 15%.

Nitin Kumar : Got it.

Tom Jorden: You know Nitin, if I could just close the gap here. You said, what did we learn? When we launched off on this project, we got a lot of questions. It started out being a 51 well project, and we all have memories of projects in our industry that were over-drilled, perhaps over-promised and under-delivered. And we said at the outset that no, this is very well calibrated. This is just an operational demonstration of what we’ve already proven to ourselves. And I said here this morning, I’m looking at the production plot. We’re obviously not sharing that, but I’m looking at a production plot of the 19 wells that are online. We have over half the wells completed in our initial 51 well bank. It’s really – if there’s anything, it’s reaffirmed our operational ability to get this done. It’s reaffirmed our calibration we’ve brought into it, reaffirmed the reservoir quality, and we are really pleased, and it’s reaffirmed our commitment to do these kind of projects.

Nitin Kumar : Yeah, and it’s really helped you guys deliver some strong results. For my second question, and I hope I’m not extending my welcome here. Tom, you are trending above 100% cash return or free cash flow this year. You’ve said in the past, you don’t want to get in an arms race. How should we think about the rest of the year? Obviously, based on your other comments, gas macro is likely to be weak. Cotera is positioned well in terms of free cash flow. So maybe just for the rest of the year, could we expect you to be closer to that 100% for the rest of the year? Or do we go, slide down a little bit because your minimum is 50?

Tom Jorden: Well, then we’re not going to pre-telegraph any activity, but I’ll always answer the question philosophically, and then you can connect the dots. We remain opportunistic. We don’t like to box ourselves in with rules, that’s why we didn’t want to enter in an arms race. I think when people make rules like that, they do themselves a disservice. We’re going to be opportunistic and right now we look everywhere, whether its assets or what have you, we look for market disconnects. Are there things where the market’s not seeing the value and can we swoop in and take advantage of that? And our buyback is squarely in our sights on that. Shane, do you want to say anything?

Shane Young : Yeah, I would just add, we’re trending as you said, kind of at or slightly above 100% in the first six months of the year. It’s interesting, if you just look at our base dividend and assume no more buybacks for the rest of the year, it gets us to about 68%, almost 70% of return for the full year. And again, we’re not going to pre-guide anything for the third quarter or the balance of the year, but I would say we continue to see our shares as a very attractive opportunity that we’ll continue to talk about and we’re likely to continue to be active in that market.

Nitin Kumar : Great. Thanks for the color guys.

Operator: Our next question comes from the line of Arun Jayaram from JP Morgan. Please go ahead.

Arun Jayaram: Yeah, good morning gentlemen, Tom and team. Tom, I wanted to get your, maybe your updated thoughts on the three-year outlook. Shane mentioned that you’ve obviously raised your 2024 oil guide by a couple of percent. If we go back to your previous three-year outlook, it contemplated 110,000 barrels of oil in 2025 and 115 in 2026. Yet your third quarter guide at the midpoint is 109, so you are almost effectively at the 2025 number, so. I wanted to see if you could just talk about qualitatively how your views on that have evolved. You obviously have a new chart in the slide deck. And I guess the buy-side question is, do we use the 5% growth number on the revised higher 2024 outlook? Sorry, that was a little messy, but that was the main point, was just do we stack the growth rate on a higher 2024?

Tom Jorden: Well look, we’re going to update our three-year guide once a year. We’re not going to be updating our three-year guide on an ongoing basis. But it’s not a three-year plan, it’s a three-year guide and this was an argument we had internally when we decided to release it. It’s a snapshot of what we think our assets and our organization could deliver based on current conditions. It’s not a capital plan that we have committed to in the out years. It’s a real plan backed with real locations, real opportunities and real results. But it’s also an organic beast, and as we outperform, we’re not necessarily going to say, ‘oh my God, we’re ahead of ourselves in our three-year plan. We have to pull back in the out years.’ That would be, I think, foolish on our part. So, I know I’m not directly answering your question, Arun, but if we end up blowing through a plan that we released in February, you are just going to have to forgive us for that.

Arun Jayaram: Got it.

Shane Young: As I said in my comments, I think we’re well-positioned to meet or exceed the plan that we looked at, at the beginning of the year.

Tom Jorden: You know, we look at our returns. Obviously, you all, I hope, are really tired of hearing us say this, and we’re going to continue to tire you out on this. We don’t manage by production goals. Well, we look at – look, we look at the world oil markets, we look at U.S. supply, we look at all of that. But mostly, we look at the return on our investment and we say, how low can that oil price fall before we’re at or near our cost to capital? And our cost of supply, we have very low-cost assets. We are really delivering robust returns that can stand a lot of price fluctuation.

A – Shane Young: So Arun, the only other point I’d make is, look, one thing we sort of learned over the first half of this year is we’ve continued to sort of push on capital efficiency and sort of what we deliver per dollar that we spend out there. And that wasn’t necessarily – where we are today wasn’t necessarily baked in to that plan when we rolled it out in February. We’ll roll out another one until the next February, but we’ve certainly been continuing to incrementally improve on capital efficiency from the time we put that plan, or from the time we put that outlook out.

Arun Jayaram: Great. And just maybe a follow-up on the 2024 program. Tom and team, you’ve designed this year to be kind of fairly balanced between your assets in Texas and New Mexico. But as we think about the well mix, about 60% of your first half 2024 program was concentrated in Culberson and Reeves. But as we look at the activity, the second half is going to be a little bit more New Mexico and Lee County. So I know all your rock is good, but are you going to be drilling, call it higher quality rock, just given how strong some of the acreage is in Southern Lee County, as we think about it on a second half versus first half basis? And maybe you could talk about some of the projects in Southern Lee that you plan to execute on.

Blake Sirgo: Yeah Arun, this is Blake. I’ll take that one. I wish I could say we strategically put stronger rock throughout the year, but that’s not really how we plan it. We have a lot of governors on our program. Obviously Windham Rose, a big concentrated project that demands a certain amount of CapEx. New Mexico is governed by a lot of things. Chicken season is the big one, and so we’re coming out of chicken season, so we’ll increase D&C activity, but also third party infrastructure. We have to get very far ahead of that and make sure we can execute those projects. And so it’s just falling out where it is more as a planning cycle, not any strategic initiative there.

Tom Jorden: And I think most of you know what Blake is referring to, but we have the prairie chicken habitat in New Mexico, governed by federal rules that prevent us from operating during day like – evening hours in certain parts of the basin. It’s something we have to manage around. By our observation, the prairie chicken is doing quite well, but we still respect their habitat and live by the regulations governing it.

Arun Jayaram: Thanks for the clarification, Tom. I was getting some incoming on what chicken season was, so I appreciate that.

Tom Jorden: Yeah, they roam free in New Mexico. If they cross the state line, they get barbecued. So it’s…

Arun Jayaram: Sounds good. My sister-in-law’s a vegan, she’ll appreciate that. Thanks a lot, Tom.

Tom Jorden: All right, yeah.

Operator: All right. Our next question comes from the line of Neal Dingmann from Truist Securities. Please go ahead.

Neal Dingmann: Good morning, guys. Very nice quarter, Tom. My first question is around your operational flexibility. You all did a really nice job of curtailing gas production and delaying tills when prices justify, unlike many of the pure gas EPs that just seem to continue to operate. And so I’m just wondering, going forward, what type of gas prices do you think are, you and Shane and the gang, are satisfactory to become more active? And then if so, how quickly then could you all move once these gas prices rebound?

Tom Jorden: Well, I’ll take that in reverse order. We can move fairly quickly. We’re looking at delaying turn-in lines, so that’s almost instantaneous, depending on price response. We would like to see netbacks north of a dollar. And yeah, we do have gathering fees, we have transportation fees. And so I would say, in the lower Marcellus, we’re probably in a pretty good drilling window if we’re north of three, competing with other places in our portfolio. That’s on netback. Now I’m quoting in IMAX price there. But the upper Marcellus, I think we’d like to see something in the mid-threes before it’s really in the game. And we do have the luxury. I don’t want to comment on other companies, but I understand. If all you had was one play, one basin, you’re in a bit of a box when things go against you.

We’ve got the luxury of redirecting. And quite frankly, we have the discipline to redirect and I hope you heard my opening comments for what they are. And they are our truth statement of how we look at the business. We are not going to – if we have to lay all activity down to zero and our production declines, that’s the right decision. And none of us like it, but the alternative is to destroy capital or to be inefficient with our shareholders’ capital, and we’re going to seek to our maximum efficiency and best returns. So we’re willing to do what it takes.

Neal Dingmann: Well said, Tom. And then my second question, just moving over to Anadarko, I think you really basically finished some activity there and certainly I think its slide five that shows you still have a lot of inventory. Just wondering, do you all believe you have ample acreage there for future development than just wondering if you’d ever consider adding anything in the play?

Tom Jorden: Well, look, we don’t think we have ample acreage anywhere. My background is exploration. So look, we would seek to add assets throughout our portfolio if they create value and the problem is, some of the marketplace is just frothy and when you get into paying very low discount rates for future drilling, that’s dangerous territory. And so we would seek places where we think we see value that the market doesn’t recognize and we do that throughout our portfolio.

Neal Dingmann: Very good. Thank you, Tom.

Operator: Our next question comes from the line of John Abbott from Wolfe Research. Please go ahead.

John Abbott: Hey, good morning, and I’m on for Doug Leggett. Tom, it is election year. As you and your team just sort of sit there and plan your business going forward, what are you watching? Where do you think you’re getting ahead of?

Tom Jorden: Well, yeah, I don’t want to get drawn into politics, but certainly we live in interesting times. We’re going to approach this very constructively. You know, I’ll say this. I think it would be naive of us to view the outcome of the election as a straight binary good versus bad. I think that the pressures on this will be different depending on the outcome of the election, but they’ll be pressures on us regardless of who wins the election. We have great faith that politicians, they campaign on one set of verbiage and then they get there and they realize, oh my goodness, we have an economy to manage and we have employment to manage, and we have geopolitical considerations and energy security, energy affordability and reality tends to temper a lot of electioneering.

So, you know, we’re – look, we’re Americans first, and whoever is in control of our government, we’re going to show up as Americans and do our part to make this country strong. I know that may sound trite, but that’s the way we view it. We don’t think that it’s a simple binary choice quite frankly. I think that this call probably isn’t a detailed opportunity to discuss this, but we’re going to pressure on this regardless of who wins. It’ll just come from different places and we’re looking, thinking ahead. We’ll be ready.

John Abbott: I appreciate it. And the next question is maybe for Shane here. So Shane, you are paying higher cash taxes this year and next. How do you kind of sort of think about your long-term cash tax rate?

Shane Young: Yeah. Well listen, I would say for the year we’re going to be a full cash tax payer. We anticipate that’s what the latest quarter showed for us as well. I think a couple of calls ago we talked about some of the changes in the code, some of the 2017 tax reform roll off and first and foremost was the R&D tax credit and the R&D expense deduction process, and that’s probably what moved us from being in that 10% to 20% range of deferred down to zero. That will ultimately unwind or normalized as it goes from a full year expense to a five-year straight line, but that’s going to take a couple of years to get to that. So I think longer term, you’ll see deferred tax move back up, but over the near term we’re going to be a pretty full cash tax payer.

John Abbott: I appreciate it. Thank you very much for taking our questions.

Tom Jorden: Thanks John.

Operator: Our next question comes from a line of Kalei Akamine from Bank of America. Please go ahead. You may be on mute if you are trying to talk.

Kalei Akamine : Sorry guys, I was on mute. Good morning. Tom, my first question is on the better performance of the Marcellus base. And I think you had mentioned some help from the lower fuel pressures. And given where prices are, that may be a prevailing industry behavior in the second quarter as guys are holding some production back. So wondering if you can help quantify the beat versus your own expectation? And as we start thinking about ’25, is there a base level of drilling activity that you’d like to hold to keep that program running efficiently?

Blake Sirgo: Yeah, this is Blake. I’ll take that one. You know, I don’t want to signal to ‘25, but I’ll talk about what we’re seeing in ‘24. Yes, we have seen some lower field pressures due to our decreased volumes from holding back tills, and that has helped the base production. But we’ve also had a wellhead compression program that we started a couple years ago in the field. And we’re still pretty early on into that, but it’s outperforming our expectations as we came into the year. And so the team’s really done a phenomenal job optimizing our wellhead program. And frankly, the volumes are just outperforming as we go into ’24, really strong base.

Tom Jorden: On the second half of your question, there is not a level of activity where we think we need to hold momentum there. And that says if we were, and we haven’t made this decision, but if we were to lay down drilling and completion activity, there’s a certain ramp up to get that back. Now we’d have deferred turn in line, so we could respond. But you’ve heard me say before that we would do that, because we think it’s prudent and we would rather miss some of the upside when we’re on ramping than fully participate in the downside, and that’s going to be our approach. All of our business units have zero-based budgeting. We look at the world fresh and we make the best decisions we can.

Kalei Akamine : Thanks for that. Next, maybe I’d like to follow-up on the Permian oil guidance, which to our mind, we’re looking at the chart on page number seven, and it looks like ‘26 has been raised from maybe 115 to maybe 120. So as you sort of assess the performance that you saw here in the second quarter across the Permian well program, could you help allocate the performance across maybe a couple of items? We see that the wells are coming on faster, hence the Row development. The wells to sales however were sort of at the midpoint, and the CapEx for the entire full corporate program was at the low end. So it seems unclear if the beat was activity led, efficiency led or productivity led. And as you assess all those things, how does that set up the ‘25 program? Could we actually see the same amount of activity for less capital?

Blake Sirgo: Yeah, this is Blake. I’ll take that one. The slide on page seven, I mean, it shows a range of where we could land on that guide. But like Tom said earlier, that’s a guide. We haven’t committed to those plans that would generate that. Really what’s driving our capital efficiency needs right now is the timing. It’s efficiency in the field, going faster on all fronts. I’ll give you an example. Our diesel zipper crew today completes 40% more footage in a year than it did five years ago. That same crew in Q2, it had a month that averaged 21 pumping hours per day and that was with two moves. We’re just really in another step change of pumping efficiency. You see the same thing on our electric crew. You combine that with our pot savings on diesel versus grid power and throw our simul-frac efficiencies on top of that.

We’re just really in uncharted territory of efficiency gains that we’ve seen and it’s increasing our capital efficiency. And as we build our plans out, those things all get incorporated. We build in our actuals and what we’ve learned, and then we will – as Tom and Shane both said, when we give our next three-year guide, that will be incorporated. The natural question is always how far can this go? Our D&C team assures me we can’t pump more than 24 hours in a day, but we’re going to give it hell.

Kalei Akamine : Thanks. I appreciate the comments.

Operator: All right. Our next question comes from the line of David Deckelbaum from TD Cohen. Please go ahead.

David Deckelbaum: Good morning, everyone. Thanks for taking my questions.

Tom Jorden: Hi David.

David Deckelbaum: I wanted to ask specifically – hey, how are you? I wanted to just ask specifically about the Harkey, which seems to be getting some incrementally positive sentiment right now. Obviously, you’ve added some wells in the Harky program. I’m curious what you’ve observed sort of in the first three that you’ve completed, that’s giving you confidence to perhaps come back and do another 12 to 20 in ‘25 and how we should think about those remaining Harky wells being developed.

Tom Jorden: Yeah David, on the Windham Row, we have not completed any of the Harky wells yet. We’ve got some drilling and we have – as Blake said, we’re coming back overfilling that row, but we don’t have any completed Harky wells on Windham yet. Again, we do expect strong performance out of those based on calibration, but we haven’t completed any yet.

David Deckelbaum : I appreciate that. Just, on just the Marcellus curtailments, just perhaps curious on how you arrived at the specificity of what you’re actually curtailing right now. I know initially you were deferring the TILs and then you brought some of those wells online. I guess, to some extent to dewater, but also to receive better pricing. How did you arrive at the 275 and would that number presumably expand if we don’t see a recovery in the gas markets or is that the portion that you believe is not earning a margin right now?

Blake Sirgo: Yeah, David. This is Blake. I’ll take that one. It’s really what you are hinting at. The way our portfolio works is our incremental volumes, the ones that sit on top, are sold into the really short-term cash markets in the basin. So the rest of our portfolio is a diversified portfolio anchored to all kinds of different indexes, whether it’s NYMEX or Power or physical deals with great floors in them. Those netbacks are much higher on the rest of the portfolio. This 275 net really represents the part of the portfolio currently exposed to in-basin pricing. As Tom mentioned, we’re kind of looking for north of $1 is what we would like to receive to bring those volumes back on. We do have other parts of the portfolio that are in summer sales right now. Those will roll off in the shorter season, and so if needed, we will have the ability to increase the curtailment. Obviously, we hope it doesn’t come to that, but we’re ready to do it if it makes sense.

David Deckelbaum : I appreciate the color.

Operator: All right. Our next question comes from the line of Michael Scialla from Stephens Inc. Please go ahead.

Michael Scialla: Good morning, everybody. You have said that you plan to do more of these multi-section developments like Windham Row. I was wondering if those are limited to Culberson County or do you have any thoughts about trying to launch those in any of your different operating areas in the Permian?

Blake Sirgo: Yeah Michael, this is Blake. The giant rows like Windham Row, that’s really going to be unique to Culberson County, just because of the acreage position we have to execute. But we chase economies of scale off our entire program. Wells per pad is a huge driver for us. You go to New Mexico, where we have multiple bin chips to exploit. It might be a small acreage footprint, but we can get a lot of wells on a pad. A lot of these efficiencies, we can carry on to smaller projects, but just not quite the level we can in Culberson County, where we can string together six, seven DSUs and just go camp out, march across, and maximize every one of these little efficiencies. It’s pretty unique to Culberson County.

Tom Jorden: Well, Culberson County is unique to Delaware Basin. When you get up into New Mexico, it’s pretty crowded. But Culberson County is a huge contiguous block of acreage that we operate, and so it really provides amazing operational flexibility, not only for configuring drilling projects such as the Windham Row, but controlling our own infrastructure, and that would include saltwater disposal, gas gathering and compression, and our electrical grid has had benefits that quite frankly, we didn’t fully anticipate when we made those decisions to control our own destiny there.

Michael Scialla : I appreciate that. I know you mentioned last quarter, looking at Windham Row, that you felt like it was better to co-develop the Harkey on, I believe, the western portion of that acreage. I think, Tom, you mentioned lower pressures in that area were part of that. I just wonder if that is, and I understand you haven’t completed any of these wells yet, but just want to see if there’s any better understanding of the key there to where you co-develop and where it’s better to independently develop the Harkey and the Upper Wolfcamp.

Tom Jorden : Yeah, we don’t have rock-solid conclusions, but some of the science experiments that we ran were actually on the eastern side of the row, and we did see a little bit of interference between the Harkey and Wolfcamp. Now, I said on our last call that even if we ignored this, these Harkey wells still are very, very attractive opportunities. But we believe that we may have a little better recovery if we co-develop. Now, we had quite a debate, because we don’t think we have rock-solid conclusions there, but we said, look, while we’re still collecting data, let’s change our default option to be co-developing, because we certainly don’t think that does any harm. So therein lies our approach. Until we see otherwise, our default option is going to be co-develop where we can. So we don’t expect to see any significant degradation because of the timing of when we’re coming back there, and we’ll continue to update you as we gather more data and make our conclusions.

Michael Scialla : Understood. Thank you.

Operator: Our next question comes from Matt Portillo from TPH. Please go ahead.

Matt Portillo : Good morning, all.

Tom Jorden: Morning. Morning.

Matt Portillo : Tom, I know it’s probably a little bit too early to specifically talk about 2025, but you gave some great color on Marcellus drilling economics with the lower being in the money at strip and the upper probably needing a little bit higher prices to justify the drill bit for next year. Just looking at the Anadarko program, it looks like you guys have had some great well results and strong returns. Just curious, is there potentially a scenario here where returns would justify dropping the remaining rig in the northeast, heading into 2025 and picking up a rig or two in the Anadarko to target that liquid rich development program that’s driving strong returns for you all?

Tom Jorden : Well, Matt, we’re not prepared to talk about ‘25 because we haven’t – we just haven’t crystallized those plans yet. But I hope I was clear from my opening remarks that my answer is hypothetically, yes. To the extent that we don’t have lease commitments, to the extent we don’t have vendor commitments or marketing commitments, we would be prepared to pivot capital anywhere to the highest productive use. So yeah, the scenario you laid out would be a possibility amongst many others.

Matt Portillo : Perfect. And then just as a follow-up question, as you mentioned, you have some summer contracts rolling off into the shoulder season. Is there any incremental color you might be able to provide in terms of how much you could potentially curtail? I know it’s going to be price dependent and kind of market dependent, but just trying to get a sense of how much that magnitude might be able to increase in October and beyond if you guys so decide it.

Blake Sirgo: Yeah, this is Blake. I can’t give you exact volumes that we could increase. Obviously we have a layered portfolio. We haven’t been putting in a lot of long term deals lately, just because of where the markets have been. But all that is considered every time we have anything coming up for expiration. But it’ll be more volume. We’re not ready to say how much.

Matt Portillo : Thank you.

Tom Jorden: You know, Matt, I just want to say one quick, make one quick point, that I don’t want it lost on the audience. When we say flexibility is the coin of the realm, that means a lot of things to us. It obviously means quality of assets, ability to have online real calibration of your economic results, willingness to pivot your capital. But all of that is made possible by flexibility in our vendor commitments. Blake and his team worked really hard during the past year and the year before it, to make sure that we weren’t locked down with annual contracts that prevented our flexibility. We have great relationships with our vendors that wouldn’t have been easy with a different vendor set. But good relationships mean we trust them, but they also trust us, because of how we behave to one another.

So I just cannot tell you how important it is to us that we have vendor relationships that allow us to lay down activity and then pick it up. We’re not locked into long term contracts. Quite frankly, if you look at the landscape, you are going to find that that is not universally true, but it’s true for Coterra, and we worked hard to get ourselves in that position. It’s a testament to Blake and his team.

Matt Portillo : Thank you.

Operator: All right. Our next question from Kevin McCurdy from Pickering Energy Partners. Please go ahead.

Kevin McCurdy: Hey, good morning, team. I think you’ve hit on the Marcellus plenty, but maybe I’ll just try to sneak one more in there. I know that you haven’t traditionally delayed turn in lines after completion in the Marcellus. Is there anything that you learned from the last batch that would change your thinking heading forward on that?

Tom Jorden : No, nothing that would change our thinking. I will say the last batch did exceed our longest shut-in time that we’ve ever had in the Marcellus. So there was some questions going around on the team on, all right, we’re kind of in uncharted waters here. What’s going to happen? Luckily, the wells look great. When we opened them up, they performed wonderfully. We were able to get all the water off of them just like we hoped, and the production results were really strong. So I think if anything, maybe it kind of reinforces our ability to keep wells shut-in longer.

Kevin McCurdy : Great. And then touching on the Anadarko. I mean, we obviously noticed the positive results this quarter, and that certainly contributed to the beat. Was there anything specific that led to the acceleration there in turn-in lines, or is that just kind of cycle times improving?

Blake Sirgo: Some of the same cycle times we’ve been discussing in the Permian, we have one cohesive D&C team at Coterra. No one operates in silos around here, and best practices, they chase like wildfire. So all the same things we’re doing in the Permian to improve our cycle times and our efficiencies, that’s also going on in the Anadarko and the Marcellus. We just don’t talk about it as much, because the capital spend is not as high. So you don’t see it quite as much. But yes, all the same great things going on with those Permian crews, it’s happening in Anadarko and Marcellus also.

Tom Jorden: That’s a hidden benefit of being a multi-basin operator and being an operator that has fluid and open communication across our platform. That a good idea in any one part of our organization spreads like wildfire. Being a multi-basin operator makes us a better operator in all three basins.

Kevin McCurdy : Great. Appreciate the time.

Operator: And we are at the allotted time. So I’ll now turn it back over to Tom Jorden for closing remarks.

Tom Jorden : Well, I want to thank everybody for joining us. As always, we prefer talking about results than undifferentiated future promises, and we intend to work hard to continue to deliver them. So, thank you very much for joining us this morning.

Operator: That concludes today’s conference. Have a pleasant day.