Coterra Energy Inc.

on a listen-only mode to 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.

Thank you, Operator. Good morning, and thank you for joining Cotera Energy's second quarter 2024 earnings conference call. Today's prepared remarks will include an overview from Tom Jordan, Chairman, CEO, and President, Shane Young, Executive Vice President and CFO, and Blake Sergo, 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 GAP financial measures were provided in our earnings release and updated investor presentation, both of which can be found on our website. With that, I'll turn the call over to Tom.

Thank you, Dan, and thank you to all that are joining us this morning. We're pleased to discuss our second quarter results with you this morning. Cotera 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. Cotera 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 to 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 and 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 2020 forecast flow. These curtailments and 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 aligned a site 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, Cotera 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 Cotera in responding to an oversupplied market will come from delaying or deferring drilling and completion investments. Remember, we do not manage Cotera 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 their, quote, 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 Cotera 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. Cotera 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 a 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 in any particular deal, but a reflection on lessons learned through the years. Cotera 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 countercyclical. 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 a missions reduction as a central tenet. 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 Lord Shane and Blake, who will provide detail on our quarterly results and outlook. First, let's hear from Shane.

Thank you, Tom, and 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 MBOE per day, with oil averaging 107.2 MBO per day and natural gas averaging 2.78 BCF per day. Oil, natural gas, and MBOE 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 a 12 previously deferred wells for a few days in June to dewater the development, but they contributed negligible volumes during the quarter, approximately 18 million cubic feet per day, or less than .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 Antidarko region, just above the high end of our guidance range. During the second quarter, pre-hedged revenues were approximately $1.3 billion, of which 75% was generated by oil and NGL sales. We reported net income of $220 million, or 30 cents per share, and adjusted net income of $272 million, or 37 cents per share. Total unit costs 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 head gains during the quarter totaled $36 million. In the quarter, incurred capital expenditures 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 tax 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 this 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 and 650 NBOE per day. Oil to be between 107 and 111 NBO per day, 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 and $530 million. Turning to full year guidance. Yesterday, we increased our 2024 oil production guidance range to be between 105.5 and 108.5 NBO per day for the year, up approximately .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 NBOE per day at the midpoint from May. During the full year 2024, we are reiterating our incurred capital guidance to be between $1.75 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 Antidarko 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 21 cent per share base dividend for the second quarter, or annualized at 84 cents per share. This remains one of the highest yielding base dividends of our peers at over 3%. Also during the quarter, Cotera 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 countercyclically 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 Cotera. 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.

Thanks, Shane. Our teams 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 frac 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 dollar 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 -over-year cost deflation and the efficiency gains we have discussed. In Culberson County, our Windham Row project is on track to meet or exceed our plans. 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 Harkie Wells to Windham Row. This brings our project well count to 57 wells. Including six Harkie Wells, which will be co-developed with the upper Wolf Camp. Additionally, our team has moved a drilling rig to the eastern side of the Windham Row. Where we have begun drilling the 16 remaining Harkie Wells that overlay the Wolf Camp. 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 frac fleet, centralized facilities and infrastructure, and the recent addition of simulfracs have lowered our Culberson cost structure 10 to 15% compared to our diesel zipper operations we previously ran in the county. Our simulfrac performance on Windham Row continues to beat our projections. And we see simulfracking as a new weapon in the holster for Cotera in Culberson County. In the Marcellus, we are currently running one drilling rig and one frac crew. We have begun completion operations on our Reyes 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 tills due to softness in local gas markets. During the month of July, we brought on those tills 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 frac activity. Currently, we are flowing back three projects, which are located in liquids rich portions of our asset. 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 NGL and condensate, who we are economics, making the Anadarko an attractive place to invest capital. At Cotera, 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. Thank you, Blake.

We now take questions and delighted to hear what's on your mind.

All right, we will now move into a question and answer session. To ask a question today, please press star followed by the number one on your telephone keypad. That again is star followed by the number one. Our first question comes from the line of Nitin Kumar from Izuho. Please go ahead.

Good morning, Tom and team. Thanks for taking my questions and congrats on a great quarter. Tom, you and Blake gave a pretty comprehensive over your of Indom role. Two specific questions around that. One, you know, as you have kind of progressed through that project and have increased wells and some of the frag, any specific learnings that we should expect to be incorporated into your program, not only in road developments, but also in your smaller permanent projects going forward or across your other operating assets. And then I just want to check. I think Blake said 10 to 15 percent cost savings, whereas the slides still say five to 15. So just just just maybe understanding what what does this project done for your costs in the Permian?

Yeah, and then none of the black handle that.

Yeah,

yeah, and the you know, really what we've seen in Windham Roe is our simul frag performances meeting or exceeding our projections. And that was a real question mark for us coming into it. Transition times on a simul frag crew is something we have never done before. And so we were 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 fracking on Windham Roe. I do see this as something that we will use quite often in Culverston County, specifically because we have the contiguous acreage. We have the high well count per pad that really makes simul frag work. As far as the other parts of the basin, we're absolutely looking at it. There is a economy of scale that you really want to get with the simul frag 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 we're looking where we can to use this even more.

And on the cost savings, is it really trending to the higher end of that five to 15 percent range?

Yeah, for the specifically when we're talking about the Windham Roe savings and it's a good it's a good market for future rows. We are trending to the higher end of that range. And that's why I quoted 10 to 15.

You

know,

if I could just close the gap here. You said, what did we learn? When we when we marched off on this project, we got a lot of questions. It started out being a 51 well project. And, you know, we all have memories of projects in our industry that were made over drilled, perhaps under under 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 a production plot. We're obviously not sharing that, but I'm looking at a production plot of 19 wells that are online. We have over half the wells completed in our initial 51 well bank. You know, it's really if there's anything, it's reaffirmed our operational ability to get this done. It's reaffirmed our calibration we brought into it, reaffirmed the reservoir quality, and we are really pleased. And it's it's reaffirmed our commitment to do these kind of projects.

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

Well, then we're not going to pre telegraph any activity. But, you know, 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 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 it's 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. Jane, you want to say anything?

Yeah, I would just add, you know, we're trending, as you said, kind of add or slightly above 100 percent 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 percent of return for the full year. And again, we're 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. Great.

Thanks for the call, guys.

Our next question comes from the line of Arun Jaram from JPMorgan. Please go ahead.

Yeah, good morning, gentlemen, Tom and team. Tom, I wanted to get you maybe your updated thoughts on the three year outlook. Shane mentioned that you've you've obviously raised your 2024 oil guide by a couple 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're almost effectively at the 2025 number. So I wanted to see if you could just talk about qualitatively how that your views on that have evolved. You have to have a new chart in the slide deck. And I guess the by side question is, do we use the five percent growth number on the on the revised higher 2024 outlook? So sorry, that's a little messy. But that was the main point was just do we stack the growth rate on a higher 2024?

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, you know, 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 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 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 on our three year plan. We have to pull back in the out years. That that would be, I think, foolish on our part. So I know I'm not directly answering your question, but but it's if we end up blowing through a plan that we released in February, you're just going to have to forgive us for that.

Yeah, as I said in my comments, you know, I think we're well positioned to meet or exceed the plan that we like that at the beginning of the year.

You know, we look at our returns. You know, 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 we don't manage by production goals. What we look at. Look, we look at the world oil markets. We look at US 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 of capital? And our our cost of supply are we have very low cost assets. We are really delivering robust returns that can stand a lot of price fluctuation. Yeah,

I think so. The only other point I'd make is look at 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 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 done continuing to incrementally improve on on capital efficiently capital efficiency from the time we put that plan or from the time we put that out. Look out.

Great. And just maybe a follow up on the twenty twenty four 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 percent of your first half twenty four program was concentrated in Culver's and in Reeves. But on the 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 on a second half versus first half basis? And maybe you could talk about some of the projects in southern Lee that you're you're you plan to execute on.

Yeah, and this is Blake. I'll take that one. The 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, you know, a big concentrated project that demands a certain amount of capex. New Mexico is governed by a lot of things. Chicken season is a big one. And so we're coming out of chicken season. So we'll increase DNC 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 not any strategic initiative there.

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

Thanks for the clarification, Tom. I was getting some incoming on what chicken season was. So appreciate that.

Yeah, they they they roam free in New Mexico. If they cross the state line, they get barbecued. So it's good.

My -in-law is a vegan. She'll appreciate that. Thanks a lot, Tom. All

right.

Yeah.

All right. Our next question comes from the line of Neil Dingman from Truist Securities. Please go ahead.

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, you know, prices justify. Unlike, you know, many of the pure gas EPs that just seem to continue to operate. And so I'm just wondering what going forward, what type of gas prices do you think or, you know, you and Shane, the gang are satisfactory to become more active? And then if so, how quickly then could you all move once these gas prices rebound?

Well, I'll take that in reverse order. We can move fairly quickly. We'll you know, we're looking at delaying turn in line. So, you know, that's almost instantaneous, depending on price response. You know, we would like to see netbacks north of the dollar. And, you know, we do have gathering fees. We have transportation fees. And so I would say, you know, in the lower Marcellus, we're probably in a pretty good drilling window for north of three competing with other places in our portfolio. That's on netback. Now I'm quoting an IMAX price there. But, you know, the upper Marcellus, I think we'd like to see something in the mid threes before it's really in the game. And, you know, 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, you know, quite frankly, we have the discipline to redirect. And I hope you heard my opening comments for what they are. And there are truth statement of how we look at the business. We are not going to, you know, if we have to lay all activity down to zero and our production declines, that's the right decision. And, you know, none of us like it. But the alternative is to destroy capital or or or to be inefficient with our shareholders capital. And we're going to we're going to seek to our maximum efficiency and best returns. So we're willing to we're willing to do what it takes.

Well said, Tom. And then my second question, just moving over to the end of the dark. I know I think you really briefly finished some activity there and certainly I think it's like five that shows you still have a lot of inventory. Just wondered, do you all believe you have ample acreage there for future development and just wondered if you'd ever consider adding anything in the play?

Well, we look, we don't think we have ample acreage anywhere. I'm a my my background's exploration. So so look, we we would we would seek to add assets throughout our portfolio if if they create value. And you know, the problem is. Some of the marketplace is just frothy. And you know, when you when you get into paying very low discount rates for future drilling, that's that's dangerous territory. And so we're we would seek places where we think we see value that the market doesn't recognize. And we do that throughout our portfolio. Very good. Thank you, Tom.

Our next question comes from the line of John Abbott from Wolf Research. Please go ahead.

Hey, good morning again. 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? What are you getting ahead of?

Well, yeah, I don't want to get drawn into politics, but certainly we live in interesting times. We're we're 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 pressure is on us will be different depending on the outcome of the election. But there'll be pressure pressures on us regardless of who wins the election. We have a we have great faith that politicians, they campaign on 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, you know, this call probably isn't the detail opportunity to discuss this, but we're going to pressure on us regardless of who wins. They'll just come from different places and we're we're looking, thinking ahead. We'll be ready.

Appreciate it. And the next question is maybe for Shane here. So, Shana, 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?

Yeah, well, listen, I would say for the year, we're going to be a full cash taxpayer. That's what we anticipate. That's what the latest quarter sort of showed for us as well. You know, I think a couple of calls ago, we talked about some of the changes in the code and some of the twenty seventeen tax reform roll off. And first and foremost was the R and D tax credit and the R and D expense deduction process. That's probably what moved us from being in that ten to twenty percent range of deferred down down to zero. That will ultimately unwind or normalize. 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 taxpayer.

Appreciate it. Thank you very much for taking our questions.

Thanks, John.

Our next question comes from the line of Kaylee Acamine from Bank of America. Please go ahead. And you may be on mute if you're trying to talk.

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

Yeah, this is Blake. I'll take that one. You know, I don't want to I don't want to signal the twenty five, but I'll talk about what we're seeing in twenty four. Yes, we have seen some lower field pressures due to our decreased volumes from pulling back tills. And that has helped the base production. But we've also had a well head compression program that we started a couple of 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 well head program. And frankly, the volumes are just outperforming as we go into twenty four. Really strong base.

You know, the second half of your question, there is not a level of activity where we think we need to hold momentum there. You know, and that that says if we if we were we haven't made this decision, but if we were to lay down drilling and completion activity, you know, there's a certain ramp up to get that back. Now we have we have deferred turn in line so we could respond. But, you know, 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. It's all of our business units are have zero base budgeting. We look at the world fresh and we make the best decisions we can.

Thanks for that. Next, maybe I'd like to follow up on the permanent oil guidance, which to our to our mind, we're looking at the chart on page number seven and it looks like twenty six has been raised from maybe one fifteen to maybe one twenty. So, as you sort of assess the performance that you saw here in the second quarter across the permanent 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 road development, the wells of 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 productivity led. And as you assess all those things, how does that set up the twenty five program? We actually see the same amount of activity for less capital.

Yeah, this is Blake. I'll take that one via 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 we haven't committed to those plans that would generate that really what's driving our capital efficiency each right now is timing in the field going faster on all fronts. I'll give you an example. Our diesel zipper crew today completes 40 percent more footage in a year than it did five years ago. That same crew in Q2, it had a month that averaged twenty one pumping hours per day. And that was with two moves. We're just really in another step change of pumping efficiency. We see the same thing on our electric group. You combine that with our savings on diesel versus grid power and throw our simulfrac efficiency 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 DNC team assures me we can't pump more than twenty four hours in a day, but we're going to give it hell.

Thanks. I appreciate the comments.

All right. Our next question comes from the line of David Dekelbaum from T.D. Cohen. Please go ahead.

Morning, everyone. Thanks for taking my questions.

David,

I wanted to ask specifically. Hey, how are you? I want to just ask specifically about the Harki, which seems to be getting some incrementally positive sentiment right now. Obviously, you've added some wells in the Harki 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 twelve to twenty and twenty five. And how we should think about those remaining Harki wells being being developed.

Yeah, David, on the on the Windham row, we have not completed any of the Harki wells yet. We've got some drilling and we have, you know, we've said Blake said we're coming back over filling that row, but we don't have any completed Harki wells on Windham yet. Again, you know, we we do expect strong performance out of those based on calibration, but we haven't completed any yet.

I appreciate that. Just on just the Marcellus curtailment, you know, just perhaps curious on on how you arrived at the specificity of what you're actually curtailing right now. I know initially you were deferring the tills and then you brought some of those wells online, I guess, to some extent to the water, but also to receive better pricing. How did you arrive at the two seventy five and with 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?

Yeah, David, this is Blake. I'll take that one. It's really what you're 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. And so the rest of our portfolio is a diversified portfolio anchored to all kinds of different indexes, whether it's NYMEX or power or, you know, physical deals with great floors in them. And so those netbacks are much higher on the rest of the portfolio. This two seventy five net really represents the part of the portfolio currently exposed to invasive pricing. As Tom mentioned, we're kind of looking for north of a dollar 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 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.

Appreciate the color.

Right. Our next question comes from the line of Michael Salia from Stevens Inc. Please go ahead.

Morning, everybody. You said that you plan to do more of these multi section developments like one of them.

Well,

one of those are limited to Culverston County or do you have any thoughts about trying to launch those in any of your different operating areas in the permanent?

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

County. Well, Culverston County is unique to the Delaware Basin. When you get up into New Mexico, it's pretty crowded. But Culverston 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.

Appreciate that. And I know you mentioned last quarter, looking at Windham Row, that you felt like it was better to co-develop the Harki on, I believe, the western portion of that acreage. And 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 you have to, or where it's better to independently develop the Harki on the upper Wolf Camp.

Yeah, you know, 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 Harki and Wolf Camp. Now, you know, I said on our last call that even if we ignored this, these Harki wells still are very, very attractive opportunities, but we believe that we may have a little better recovery if we co-develop. Now, you know, we had quite a debate because we don't think we have rock solid conclusions there, but, you know, 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. And so therein lies our approach. Until we see otherwise, our default option is going to be co-developed where we can. So we're, 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. Thank you.

Our next question comes from Matt Portilla from TPH. Please go ahead.

Good morning,

all. Morning.

Morning. 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, 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?

Well, Matt, we're not prepared to talk about 25 because we haven't, you know, we just haven't crystallized those plans yet. But I hope it was clear from my opening remarks that my answer is hypothetically, yes, we would, we, 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, that the scenario you laid out would be a possibility amongst many others.

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 decided.

Yeah, this is Blake. I can't give you exact volumes that we could increase. You know, 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.

Thank you. You know, Matt, I just want to say one quick make one quick point that I don't want lost on the audience. You know, when we say flexibility is a 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 economic results, willingness to pivot your capital. But all of that is made possible by flexibility in our vendor commitments. You know, 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 that prevented our flexibility. We have great relationships with our vendors that wouldn't have been easy with with a different vendor set. But, you know, good relationships mean we trust them, but they also trust us because of how we behave to one another. And so I just cannot tell you how 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. And quite frankly, if you look at the landscape, you're going to find that that is not universally true, but it's true for Kotera. And we've worked hard to get ourselves in that position. The testament to Blake and his team.

Thank you. All right. Our next question comes from Kevin McCurdy

from Pickering Energy Partners. Please go ahead.

Hey, good morning, team. I think you hit on the Marcellus plenty, but maybe I'll just try to sneak one more in there. I know that you have a 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?

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. And so there was some 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.

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

You know, some of the same cycle times we've been discussing in the Permian, you know, we have one cohesive DNC team at Cotera. No one operates in silos around here. And best practices, they chase like wildfire. And 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 all the same great things going on with those Permian crews. It's happening in Anadarko and Marcellus also.

You know, 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 organizations spreads like wildfire. Being a multi-basin operator makes us a better operator in all three basins.

Great. Appreciate the time.

And we are at the allotted time. So I'll now turn it back over to Tom Jordan for closing remarks.

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.

That concludes today's conference. Have a pleasant day.