APA Corporation

Good day, and thank you for standing by. Welcome to the APA Corporation's third quarter 2023 results conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you'll need to press star 1 1 on your telephone, and you will then hear an automated message advising you that your hand is raised. To withdraw your question, please press star 1 1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead.

Good morning, and thank you for joining us on APA Corporation's third quarter 2023 Financial and Operational Results Conference call. We will begin the call with an overview by CEO and President John Chrisman, Steve Reine, Executive Vice President and CFO, will then provide further color on our results and outlook. Also on the call and available to answer questions are Dave Purcell, Executive Vice President of Development, Tracy Henderson, Executive Vice President of Exploration, and Clay Bratches, Executive Vice President of Operations. Our prepared remarks will be about 10 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you've had the opportunity to review our financial and operational supplement, which can be found on our investor relations website at investor.apacorp.com. Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discussed today. Full disclaimer is located with the supplemental information on our website. And with that, I'll turn the call over to John.

Good morning, and thank you for joining us. On today's call, we will review third quarter highlights, discuss our outlook for the fourth quarter, and provide a high-level overview of our capital plan and anticipated production in 2024. For the third quarter in a row, adjusted oil production exceeded the high end of our guidance range. Good execution and strong well performance in the Permian are the primary drivers of this trend. We also achieved the high end of our guidance in the North Sea during the quarter, which benefited from the production ramp of the store north well. In Egypt, gross oil volumes grew by approximately 4,000 barrels per day, which was a bit below expectations as previously disclosed. On a total company basis, Third quarter reported oil volumes were up more than 15% from the same quarter in the prior year, and we are very pleased with this progress. Activity in the U.S. and Egypt remained steady while we suspended drilling activity around mid-year in the North Sea. Our investment program in the North Sea is now directed towards safety, base production management, and asset maintenance and integrity. In Suriname, we achieved a very important milestone during the third quarter with the completion of a successful appraisal drilling program at Crab Dagu on Block 58 and the subsequent announcement by our partner, Total Energies, of plans to proceed with feed work for a 200,000 barrel per day FPSO in the eastern portion of the block. The planned oil hub is underpinned by an estimated 700 million barrels of recoverable oil resource at Sapakara and Crab Dagu and is targeted FID by the end of 2024. Turning now to our outlook. In yesterday's financial and operational supplement, we issued fourth quarter guidance, which anticipates slightly lower production on a BOE basis compared to the third quarter. The primary contributor is in the North Sea, where the temporary shut-in at Barrel Bravo will result in volume deferrals of about 5,000 barrels of oil equivalent per day. In the U.S., completion timing will lead to a relatively flat quarter consisting of unchanged oil production and a small decline in natural gas. And in Egypt, a combination of higher oil and lower natural gas volumes should deliver BOE growth. but not enough to fully offset the downtime in the North Sea. Let me provide a bit more color on production operations in Egypt. In February, we established a gross oil target of 154,000 barrels per day for the fourth quarter. We now estimate that number will be closer to 150,000 barrels per day, which is up about 5,000 barrels per day from the third quarter. After successfully working through the challenges associated with ramping our rig count from 11 to 18, our drilling program is now performing as planned. However, we have experienced a growing backlog of workover projects over the last two quarters and a corresponding uptick in barrels offline. To address this, we have begun to increase our workover activity, which Dave can discuss further in Q&A. During the fourth quarter, we are opportunistically accelerating the completion of eight Permian wells from January into December and adding a sixth rig in the Delaware Basin. This will result in an increase in our estimated fourth quarter upstream capital to around $500 million and bring four-year upstream capital to just under $2 billion. I should note that these investments will not have a material impact on fourth quarter production. As we typically do at this time of year, I would like to provide a high-level overview of our 2024 outlook, which we will follow up with formal guidance in February. Recall that we entered 2023 with a planned upstream capital budget of $2.0 to $2.1 billion. As of today, we expect a similar range in 2024, albeit with some changes in regional allocations. We are targeting low single-digit oil production growth next year, with expected increases in the Permian and Egypt more than offsetting declines in the North Sea. APA remains committed to returning at least 60% of our free cash flow this calendar year to shareholders. During the first three quarters of the year, we generated $673 million of free cash flow, 65% of which we returned to shareholders via dividends and stock buybacks. This leaves more to do in the fourth quarter and we will fulfill our minimum 60% commitment for the full year. One of APA's core principles is to produce oil and gas safely and to reduce the environmental impact of our operations. I am pleased to announce that we recently achieved an important milestone in reducing methane emissions with the conversion of over 2,000 pneumatic devices in the Permian to lower emitting technologies. Our programs to identify and eliminate emissions throughout our global asset base are ongoing, and we continuously seek to expand and improve them. In closing, we are committed to our strategy of maintaining a diversified portfolio and maintaining operational flexibility to respond quickly to commodity price volatility and other externalities. We are demonstrating this today through the reallocation of capital from the North Sea into the Permian and Egypt. We also remain committed to the investment in a portfolio of exploration projects which have the potential to drive differentiated future growth and competitive full cycle economics. And with that, I will turn the call over to Steve Ryan.

Thank you, John, and good morning. For the third quarter, under generally accepted accounting principles, APA reported consolidated net income of $459 million, or $1.49 per diluted common share. As usual, these results include items that are outside of our core earnings, the most significant of which was a $93 million release of a valuation allowance on deferred tax assets. This was offset by a loss on the quarterly mark-to-market of our kinetic stock ownership and unrealized derivative losses on our Waha basis swaps. Excluding these and other smaller items, Adjusted net income for the third quarter was $410 million, or $1.33 per share. Free cash flow, which for external purposes excludes changes in working capital, was $307 million in the quarter. Through dividends and share repurchases, we returned 32% of this amount to shareholders during the quarter. As John indicated, year to date, we have returned 65% of free cash flow to shareholders. Please refer to APA's published definition of free cash flow for any reconciliation needs. In our 3Q earnings prerelease, we anticipated G&A expense would be significantly higher than our underlying run rate of costs, which is around $100 million. For the quarter, reported G&A was $139 million, mostly because of APA stock price appreciation and the mark-to-market impact on previously accrued share-based compensation. As we have explained in the past, the marked market of share price movements also impacts LOE, CapEx, and exploration expense. Thus, these items were also higher during the third quarter for the same reason. North Sea taxes also came in above guidance in the quarter by $46 million. This was the result of an incremental cargo lifting late in the quarter, which was not anticipated at the time we provided 3Q guidance in August. In accordance with generally accepted accounting principles, we recognize cargo listings in the quarter they occur, which increases revenue and current tax expense, but has no impact on reported production volumes. To be clear, though, this is just a movement of revenue and income tax expense from the fourth quarter into the third quarter and has no impact on our anticipated full-year North Sea production, revenue, or income tax expense. As previously noted, Our Chenier gas sales contract commenced on August 1st and contributed two months of free cash flow in the third quarter. You will find this impact on our P&L in the two line items which capture the revenue and costs associated with oil and gas purchased for resale. In the third quarter, the Chenier contract contributed free cash flow and pre-tax income of $32 million. We currently anticipate it will contribute approximately $90 million in the fourth quarter and $375 million for the full year 2024. In closing, as anticipated, the second half of 2023 is poised for improving production and free cash flow versus the first half of the year. With the improving performance, we are tracking very close to our original full year guidance across most of our key financial and operational metrics for the year. We will continue to return capital to shareholders through dividends and share repurchases. And while our balance sheet is much stronger than a few years ago, we continue to recognize the need for further progress on debt reduction. And with that, I will turn the call over to the operator for Q&A.

Thank you. At this time, we'll conduct the question and answer session. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. Please limit yourself to one question and one follow-up. If you have additional questions, we ask that you disconnect and rejoin the queue. Please stand by while we compile the Q&A roster. And our first question comes from Doug Leggett with Bank of America. Doug, your line is open. Please go ahead.

Thank you. I think Gary just lost a bet on name pronunciation, but thanks for getting me on. Guys, the North Sea, I wonder if you can offer a little bit of color on what you see as a decline curve there with no capital. And where I'm going with this is, obviously, you've got... I believe the gas compressor, you know, these are all the assets. I guess you're having to take it off the platform and so on. That's going to come back. And obviously production will decline because you're not spending any money. But my question is, how does the decline look versus the free cash flow in the North Sea? It strikes me that the free cash flow in a declining curve could actually be higher.

Yeah, Doug, it's a good question. You know, we're in the process right now working through the 2024 plan. You know, clearly we've got some downtime that we've announced in the North Sea in the fourth quarter as we do have a compressor that we had to haul, you know, on shore. We'll get that back on, you know, sometime early next year. And then you'll be back at your, you know, your base decline, you know, both for 40s and barrel. The 40s, you know, is underwater floods, so it's got, you know, a much lower decline than barrel. But we do not have the rig. We'll continue to, you know, focus on maintenance, integrity, projects, and we'll come back early next year with, you know, with a detailed look when we give out the 24 plan.

But is it fair to say that versus 2023, when you were spending capital, free cash flow could be higher, John?

I think it's early on the... Yeah, Doug, I think it's, as John was about to say, I think it's a bit early to state that for 2024. It's certainly a possibility, but let's get to February. We'll have a detailed plan, and then we'll know kind of what type of price environment we're looking at as well, and we'll have a better analysis on that at that point in time.

All right, thank you. John, my follow-up's in Suriname. I managed to get a red eye to Total's analyst there this year and asked Patrick a very specific question about timing. And I wanted to get your perspective on this. My understanding is that the 2028 schedule for First Oil assumes a 42-month new-build FPSO. But since that announcement, I understand that SBM has been selected with an early hull In other words, a year earlier on that timeline was some 70% expected to be contracted at the time of FID. I know you're not the operator, but I wonder if you could confirm or offer any color around those points.

I would just say for now, I mean, you know, kind of the official timeline is FID by the end of 24 and, you know, first oil by 2028. But obviously, you know, there's incentive and motivation to try to accelerate that. And I would expect that they will do everything they can to do so.

Fair enough. Thanks, guys. Thank you.

Stand by for our next caller. And that is John Freeman with Raymond James. John, your line is open. Please go ahead.

Good morning, guys.

Good morning, John.

Yeah, the first question I had on the six rigs that's getting added in the Permian, is the plan for that rig to operate exclusively in the Delaware or potentially toggle between Delaware and Alpine High?

John, it's a spot rig we're picking up. It'll kind of go pad to pad. It will start in the Delaware on some oil pads, but then there's flexibility. And we'll come back in February with a little more detail, obviously, on the 2024 plan and how that would sit.

Okay, and then just my follow-up question, I appreciate the preliminary sort of outlook on 2024. If I take kind of what you said about, you know, the budget being in a kind of flattish versus 23, and I think about, like, you know, the sixth rig, that's largely kind of funded with the North Sea CapEx reduction, and then, you know, Egypt, you've said previously, is kind of status quo next year. And so it seems like just of your... your three main operating areas, that's kind of flash and the wild cards kind of expiration. Was your commentary about kind of a flash budget, does that all end? Does that include the expiration side? If you can kind of just walk us through kind of how you see the expiration in a year where there's probably a step down in activity and turn on the head FID.

Yeah, John, it's a great question. Yes, it includes... About $150 million of expiration. I think you laid it out pretty accurately. You'll see a full year without drilling in the North Sea. You'll see an increase in the Permian, relatively stable drilling lines in Egypt, and you will see about $100.5 million in terms of expirations, what we're sketching out at this point. relatively stable program with continued exploration investment like we've done over the last several years.

Thanks, John. I appreciate it.

You bet. Thank you.

Our next question comes from Bob Brackett with Bernstein Research. Bob, your line is open. Please go ahead.

Yeah, good morning. You talked about, in terms of the Permian, if we think about 12 net completions in 3Q, you're kind of driving flat production Q on Q and 4Q. 20 net completions in 2Q allowed you to grow the following quarter, and it sounds like you've already connected 12 wells in October with 18 coming in the rest of the Q and Does that imply a pretty strong cadence into sort of one queue of next year in terms of the Permian?

Yeah, it's a good question. You know how timing of completions drives the quarterly production cadence. This is Dave Purcell, by the way. The remaining completions this quarter will be weighted more towards December. And then we'll provide you in February with what the cadence of completions looks like in 24. And as you can imagine, there'll still be some lumpiness. And we'll provide that in February once we get the plan finalized.

OK. Quick follow up. If there is an FID in 24 around Suriname, does that change that CapEx budget of 2.0 or 2.1, or it's kind of a rounding error?

No, at this point, we've factored that in, Bob.

Okay, very clear. Thank you. Thank you.

Our next question comes from Neil Dingman with Truist Securities. Neil, your line is open. Go ahead.

Thanks for the time. John, my first question is just on Egypt. I'm just wondering if the 24 plans will continue to have sort of a similar level of exploration development activity, and if so, you know, should we assume somewhere around, I mean, in your estimate, around that sort of same drill and success next year?

Yeah, Neil, program will be, you know, pretty stable. We're running 18 rigs in Egypt, and, you know, it is a steady diet of both development and exploration. and anticipate that to be very similar next year. And we do, you know, expect to be able to continue to show good growth in Egypt.

Very good. And then my second, John asked a little bit on this, but just on the Permian gas plans, I'm just curious if your decision, you know, if and when to go back and boost that activity, is that based more on how those gassy well economists compete against your oily southern Midland or Delaware economics, or is it just simply if those gas returns would provide, you know, a certain rate of return?

Yeah, I mean, it's really more a function of, you know, stability in the Waha pricing. And, you know, the wells we've drilled this year have been strong and, you know, very competitive. I mean, I think at $3 Waha, they're very, very competitive with Permian oil. So, But it's really more a function of, you know, when we believe we'll have stability there at Waha that, you know, you can produce some end of the infrastructure.

Perfect. Thanks, John.

Our next question comes from Scott Gruber with Citigroup. Scott, your line is open. Go right ahead.

Thanks. You know, just coming back to Egypt, you mentioned growth next year. Is that going to be on a year-to-year basis, or do you think the exit-to-exit will be up as well?

Yeah, we'll give you the details when we roll out the plan in February, but we'll show growth most likely year-to-year and exit, but let us give you those details in February.

Okay. um and then just you know think about the next few years you have a project you know that would be moving forward and in suriname and obviously you have the the carry uh from total um they still have a billion dollars or so of commitment can you just speak to um you know whether that uh impacts your your cap allocation across the the rest of the portfolio on a multi-year basis

Yeah, I mean, we look at the multi-year plan, and that's the beauty of the carry is it's going to keep that in a very, very manageable place from where we've been. So, you know, I mean, we basically structured that deal, you know, banking on success, and you'll see that, you know, start to follow through if, you know, we move through the next phases. So got to FID a project first, but that's where the carry will kick in.

Got it. Appreciate it. Thank you.

Our next question comes from Roger Reed with Wells Fargo Securities. Roger, your line is open. Go ahead.

Yeah, thanks. Good morning. Just to follow up, Egypt had a little release of capital or working capital this quarter. Just how do you think that looks going forward? And also in Egypt, given that they've had some gas issues related to imports, in the MED, any interest or pressure from Egypt to have you increase gas production there? Is that something that could occur in 24? That's not really a reasonable assumption given locations of fields and, you know, takeaway capacity, et cetera.

I mean, there's no doubt Egypt, you know, needs more gas production. We're flowing everything we can into the grid, which is where our gas goes. You know, our program has been focused on oil, as we received 265 for MMBTU there. But, you know, short-term, there's not anything we could do to increase gas production. But there are some longer-term projects, but we, you know, would need to work on a higher gas price there.

And on the working capital, thoughts?

Yeah, on the working capital, this is Steve. So we did have an increase in working capital in the quarter in Egypt, as you will see in the supplement. So the receivables did go up during the quarter, but receivables from EGPC actually went down during the quarter. And if we go back to the first quarter of this year, when I think the The concern about the payments from EGPC kind of surfaced at that point in time with the first quarter results in May. Since that time, you know, from first quarter, end of first quarter to the end of the third quarter, EGPC receivables have gone down and so have the past due receivables from EGPC. So I think we're in good shape there. We've made making progress. We've made some good progress. And as John always says, we're in constant contact with the highest level folks in Egypt about managing that receivable balance. So we're making some good progress there. More to go, but we're making good progress. I think the issue with or the reason why receivables went up in the third quarter is because we were exporting more cargoes and selling them to third parties and those third-party receivables have gone up during the quarter because we were third-party receivables were low at the end of the second quarter and higher at the end of the third quarter. So those are receivables that are just paid under normal terms from our normal credit worthy and on time paying purchasers of the oil coming out of Egypt in export cargos.

And that's, in that situation, just normal seasonal or month-to-month kind of changes, nothing to read into that, presumably.

Right, right. And you'll see there's a, you know, at the corporate level, not just in Egypt, at the corporate level, there's a meaningful increase in working capital during the quarter, and that also is just seasonal type things we've We had some payables in particular, a large one around taxes, large cash payment and taxes in the UK that comes in the third quarter. And so a lot of seasonality to working capital movements for the company as a whole.

Appreciate the explanation. Thanks.

And our next caller is Charles Mead with Johnson Rice. Welcome, Charles. Your line is open.

Hi, good morning. This is Michael Furrow actually filling in for Charles Mead.

Hello, Michael.

All right. Okay, just one question for me regarding Suriname. I know FID is not expected until late in 2024, and this might be a bit premature, but when do you think that further exploration could occur within Block 58? And I recognize that Total is the operator here, so maybe a better way to frame it would be when would APA like to further explore Block 58 and maybe if you could even speak on Block 53?

No, it's a great question. You know, the focus this year was appraisal of crab daggers so we could, you know, start a project in terms of getting it moving into the next phase. And, you know, we're in a position to do that now. We do see, you know, several high-quality, low-risk prospects in Block 58. A lot of the program at Crab Dago that, you know, obviously appraised that fairway also de-risked, in our mind, a lot of prospects. There's no urgency in terms of getting to them, you know, in 24, but we will be working through those, you know, with our partner. And when I look at the two blocks, we see more prospectivity in 58 over 53. We're working with our various partners there on the next steps at Baja, but I think we would see more prospectivity in 58 over 53 at this point.

All right. I appreciate that, Culler. Thanks for your time. Yep. Please stand by for our next question.

And our next question is from Scott Hanold with RBC Capital Markets. Scott, your line is open.

Yeah, thanks. My question is going to be on just general exploration. I mean, obviously, you've got Cernem going on, but more recently, you've kind of farmed in a position in Alaska. And on top of that, obviously, you've got different things in Uruguay and Dominican Republic. Can you Tell us in general, just first maybe starting with Alaska and then how you think about these other prospects moving forward for APA.

Alaska fits our exploration strategy, and that is trying to build a high-quality portfolio. We've got a proven operator. It's state lands, very, very prospective acreage, and it's something we look forward to sharing more in February. And it's all about, you know, a portfolio on the exploration side and having choices to high-grade and, you know, drill the best things, you know, that are going to create the most shareholder value.

So when I think of APA and look, I mean, it seems to be in contrast with, you know, some of, I guess, your U.S. or even just E&P peers where, you know, there's a lot of, I guess, M&A going on there for, you know, domestic shale, but it looks like APAs take a little bit different angle or – you know, is there still a desire to potentially maybe even bulk up in the Permian or other focus areas, you know, where you do have, you know, more, I guess, you know, proven production at this point?

Yeah, I mean, I think we like to look at, you know, both avenues, both the organic and the inorganic. And, you know, we stayed committed to an exploration program. And, you know, you're seeing that pay off in the you know, Suriname and longer term. But I also think you saw us last year bolster, you know, some, you know, some acreage in the Delaware. So, you know, it's a diet of both that you're constantly looking at. And, you know, you've got to continue to focus on adding to the assets as well as, you know, what can create, you know, value for your shareholders.

So when you look at the Permian Basin, do you all feel at a five, six rig pace, you've got what you'd say ample inventory of kind of tier one stuff?

Yes. I mean, I think with where we sit today, five to six rigs, you know, they would save into the decade pretty easily. And that's focused on higher quality, longer laterals. And we're always, you know, we've got a nice footprint that we're always moving inventory from one category of, you know, up into the high graded as we continue to test and, you know, find ways to make it all work.

Appreciate the call. Thanks.

You bet.

Our next question comes from David Deckelbaum with TD Cowen. David, your line is open.

Thanks for taking my questions, guys. John, I wanted to just ask, are you able to tell us the $150 million you have earmarked for exploration next year? I guess to be more pointed about it, how much of that is included for ex-Suriname exploration?

At this point, we'll come back with more color next year on the program. It's a placeholder, and we're working through. There's some other things we'll be doing. You've got exploration in Egypt that we've always funded and some other things, but we'll come back with more color in February.

I appreciate that. Maybe if I could just follow up on Egypt. You talked about the growth trajectory in the next year, and I certainly know that U.S. oil is anticipated growing next year. Can you give a little bit more color just on what's happening with the increased work over activity? What's driving that? And, you know, are there any alterations being made that this won't be a drag into next year? Is this being factored in with greater frequency now that you have this increased rig count?

Yeah, I mean, it's a situation where we've always had a, you know, I'll call it a wells or a volume offline that requires work over. We have a lot of sub pumps in Egypt, and we've had some increase in the failures in a few areas, and that number's ticked up, and they can get into some more color. But, you know, we've just got more barrels offline that we need to get to on the work oversight, and we're addressing that. So it's, you know, it's something we're jumping all over.

Yeah, and so just to follow on what John said, we're working on a root cause analysis just to understand, are we seeing a structural change in Well failures, we've seen a reduction in ESP runtimes, but we're doing a broader look at that. And to put some numbers on John's comment on base level of work over inventory, that typically represents about 5,000 barrels a day of production that's offline at any given time. We've seen that increase to over 10,000 barrels a day really from the end of the second quarter through today. And so we've added a work over rig, and we're doing some other things to start working that backlog down over time.

Is that in coincidence with where you're developing right now, or is it just sort of circumstantial to just across the entire area?

It's across the entire western desert, and we're working the root cause on that just to understand are there any specifics, but right now we haven't identified any.

Thank you, guys.

As a reminder, to ask a question, just press star 1-1 on your telephone and wait for your name to be announced. And our next question comes from Leo Mariani with Roth MKM. Leo, your line is open. Go ahead.

Hey, guys. Just wanted to follow up briefly on Egypt here. I think you guys maybe added a rig recently. I think you were at 17 earlier in the year, if I sort of got it right. So just curious, is that just because of lower North Sea activity? You're just kind of reallocating dollars here. And then I guess just in general, obviously there's been significant instability there, kind of in that Sinai Peninsula area, bordering Israel there with the conflict that's happening right now. I mean, do you guys have any concerns over potential... You know, spillover, you know, into Egypt, and have you been kind of in contact with the Egyptian government regarding that?

Yeah, it's something that, you know, it's interesting. We're coming up on our 30th anniversary of being in Egypt. So, you know, we've got a great history there. We've been there a long time, and we've been through, you know, watched Egypt go through a lot of trying times. You know, this year has been difficult for them and it's really been driven more by inflation and currency devaluation and some of those factors. You know, we're closely monitoring the situation. You know, I think the good thing from our perspective is our operations are all west of Cairo into the western desert. And if you go back in history, even over the Arab Spring, you know, we have not had any, you know, shut-ins or major interruption in our operations. So, you know, I think the good news there is the government continues to prioritize oil and gas operations. They know they need the in-country production. And, you know, we've been watching things very, very closely.

Okay, that's helpful. And then, you know, in terms of the $150 million in exploration next year, I don't want to beat a dead horse here, but as you kind of look at it at a high level, in your mind, does that include some dollars in Suriname at this point, or is that just sort of kind of still an open-ended proposition?

It's, in general, you know, right now it's a placeholder for the things we want to do, but, you know, there's seismic that'll be, you know, is being shot in Suriname and where would be the development area, some other things, so You know, it'll capture our exploration spend for next year, and, you know, we'll come back with more details in February.

Okay, thanks.

And our next question comes from Jeff with Daniel Energy Partners. Go ahead, Jeff.

Hey, guys. Thanks for taking the question. Really, my question is around, you know, U.S. oil production, which looks like it's taking a pretty impressive step change up. I mean, obviously, you completed some more wells, but, you know, obviously several quarters where it was just kind of locked into the 70s. Now we've taken this, you know, 8,000 barrel a day step up in Q3. And I'm wondering, you know, A, why change, and B, if there's something that's happened that has kind of prompted this decision to add another rig in the Delaware. Thanks.

I mean, it's really just a continuous program. I mean, we're seeing the benefit of the, you know, the deliberate approach we've taken. We've been focused on long laterals and really locking the, you know, the rig lines down and giving the teams time to execute. And, you know, you're seeing that. We've continued to drill long laterals and we're continuing to have good results. It's really just a function of the timing of the completions. You know, in terms of adding the sixth rig, it's really more allocation of capital from the North Sea into the Permian. And, you know, but we look forward to continuing to deliver strong results. And if you look, fourth quarter is a little flattish compared to third quarter. A lot of that's because third quarter is running ahead, you know, versus fourth quarter running behind. So, you know, very, very pleased with the execution level in the U.S.

Excellent. Thanks, guys. I appreciate it.

I am showing no further questions at this time, so this concludes the question and answer session. I would now like to turn it back to John Christman, President and CEO, for closing remarks.

Thank you for participating on our call this morning. I want to leave you with the following thoughts. We've completed a successful appraisal program in Suriname at Sapakara and Krabdagu and will advance a project through the feed process during 2024. In Egypt, gross oil production continues to increase on the success of our drilling program. And lastly, we continue to deliver outstanding results in the Permian, where we've added a sixth rig, which will add to the momentum as we enter 2024. We look forward to telling you more about things in February, and thank you for the call.

And this does conclude the program. You may now disconnect.