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spk04: Hello, and thank you for standing by. Welcome to APA Corporation's third quarter 2022 results conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1 1 on your telephone. It is now my pleasure to introduce Vice President of Investor Relations, Gary Clark.
spk15: Good morning and thank you for joining us on APA Corporation's third quarter 2022 financial and operational results conference call. We will begin the call with an overview by CEO and President John Christman. Steve Riney, 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, Senior Vice President of Exploration, and Clay Bratches, Executive Vice President of Operations. Our prepared remarks will be less than 15 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our third quarter 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 most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with the 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. A full disclaimer is located with the supplemental information on our website. And with that, I will turn the call over to John.
spk06: Good morning, and thank you for joining us. On the call today, I will review highlights from the third quarter, provide commentary on our fourth quarter outlook, and conclude with an early look at our 2023 plan. APA continues to enjoy a robust free cash flow profile provided by our unhedged exposure to a globally diversified product price mix. With activity in Egypt and the Permian Basin now at levels capable of driving sustainable corporate production growth, our free cash flow is also expected to grow. assuming flat year-over-year oil and gas prices. Turning to the third quarter results, we have had several key highlights. Global production was in line with our guidance range as outperformance in the U.S. offset unplanned facility downtime in the North Sea. Permian Basin assets were strong contributors across the board, from the core Midland Basin Development Program to the newly acquired properties in the Texas-Delaware. In Egypt, drilling and recompletion programs are progressing closer to our original plans for the year. New well connections exceeded our revised third quarter guidance, and production momentum is picking up into the fourth quarter. The challenges associated with the activity ramp are not totally behind us, but we are making good progress. The North Sea, after returning to production from seasonal turnarounds, incurred an unusually high amount of unplanned downtime in August and September. Most of these issues have been mitigated and volumes have returned to a more normalized level as reflected in our forward guidance. During the third quarter, we generated more than $600 million of free cash flow, purchased nearly 10 million shares of APA common stock at an average price of $33.85 per share, and announced a doubling of our annual dividend rate. In Suriname, we advanced our exploration and appraisal program with the first oil discovery on Block 53 at Baja and a successful flow test of the Crab Dagu discovery well in Block 58. And on the ESG front, I am very pleased to announce that we have successfully delivered on our 2022 goal to reduce flaring in Egypt. Today, new projects are reducing routine upstream flaring by 40%, enabling us to compress the gas into sales lines and deliver to Egyptian consumers for cleaner burning affordable fuel. More information on our third quarter results can be found in the operational supplement posted on our website. Turning now to our fourth quarter outlook, capital investment is projected to be around $450 million and our four-year guidance of $1.725 billion remains unchanged. We expect adjusted production will increase by around 5% from the third quarter, driven primarily by an increase in new well connections and recompletion activity in Egypt, and a rebound from planned and unplanned platform maintenance downtime in the North Sea. Given the age of the North Sea facilities, we expect facility run times will generally be lower and more variable than in the past. As a result, we are now providing a production guidance range to accommodate a broader spectrum of potential future outcomes. In Suriname, on Block 58, we are currently participating in the drilling of two wells, a second appraisal well at Sapakara South and an exploration well at Awari. Results will be provided as they become available. Despite a few challenges during 2022, we will exit the year in a strong position, financially and operationally. We are on track to generate around $2.7 billion in free cash flow for the year. Consistent with our 60% capital returns program, we anticipate returning at least $1.6 billion of this in share buybacks and dividends. While there is more to do, we have significantly strengthened our balance sheet, reducing net debt by more than $1.4 billion through the end of the third quarter, and production volumes are now trending sustainably higher in the US and Egypt. As we plan for 2023, our objectives remain the same. We will maintain capital discipline, target moderate production growth, work tirelessly to mitigate rising costs, and continue to deliver meaningful emissions intensity reductions. Our capital budget next year will be around $2.0 to $2.1 billion. This assumes five rigs in the Permian Basin and up to 17 rigs in Egypt, while activity in the North Sea and Suriname is projected to remain consistent with 2022 levels. Similar to our approach in 2022, This early view incorporates what we believe is an appropriate view of inflationary impacts on the capital program. The majority of the expected inflation is associated with U.S. rig and frack costs as contracts are renewed at the higher current rates. Inflationary pressures in our international portfolio should be more muted. Despite the planned increase in capital investments, In a like-for-like price environment, we estimate APA's free cash flow will grow in 2023. Note this excludes any uplift from our Chenier gas supply contract commencing in the second half of the year. Steve will provide more details on this contract, which gives us access to premium natural gas price points in Europe and Asia. Following three years of production decline since the beginning of the COVID pandemic, We look forward to returning to growth in 2023. At the corporate level, we are targeting mid single digit year over year growth, driven primarily by higher oil production across all assets. In the third quarter, our Permian Basin results were particularly strong due to a variety of factors, including good underlying base production and new well performance, the timing and number of new completions, and relatively minimal maintenance midstream and weather-related downtime. As we look into the fourth quarter of 2022 and the first quarter of 2023, we expect Permian production will be flat to down as we experience a lull in new well connections and reflect the potential for winter weather-related downtime in our outlook. Planning for next year continues. and we will have much more detail to provide with our fourth quarter results in February. In closing, we have a constructive outlook on the long-term demand for natural gas and oil. This hasn't changed despite the potential near-term demand impacts of a recession and the ongoing debate over the pace of global decarbonization trends. We continue to plan our business using relatively conservative commodity price scenarios, allocate capital to our highest return projects, and target long-term single-digit sustainable production growth. APA will continue to return 60 percent of free cash flow to shareholders through buybacks and dividends, while also continuing to strengthen the balance sheet. Lastly, we remain committed to reducing emissions within our operational footprint, and we will be introducing specific CO2-equivalent emissions intensity goals around this objective in the near future. And with that, I will turn the call over to Steve Reine.
spk14: Thank you, John. For the third quarter of 2022, APA Corporation reported consolidated net income of $422 million, or $1.28 per diluted common share. Our quarterly results include items that are outside of APA's core earnings. The most significant of these was a $275 million charge for the impact of the UK energy profits levy. This was partially offset by a $93 million release of tax valuation allowance due to the use of tax loss carry-forwards during the quarter. Excluding these and other smaller items, adjusted net income for the third quarter was $651 million, or $1.97 per diluted common share. Most of our financial results in the third quarter were in line or better than guidance. For the quarter, we reported a net gain of $12 million on the sale of oil and gas purchased for resale. This was better than the guidance we provided in August of a $10 million loss. As a reminder, we sell our gas in-basin at Waha Hub or El Paso Permian-based pricing. Our marketing organization fulfills obligations on various commercial agreements including our long-haul transport contracts using purchased product. The reported gain or loss on the sale of oil and gas purchased for resale is a result of this latter activity. In the fourth quarter, based on recent strip pricing, we expect this activity to result in a net gain of approximately $70 million. GPT expense, which is costs incurred for gathering, processing, and transmission, was above guidance for the third quarter. This has been a trend for much of 2022 and is primarily a result of the higher natural gas prices in the U.S. GPT expense increases with gas price because some of our gas processing contracts are based on the percentage of proceeds, and accounting for such contracts results in costs going up and down with movements in gas price. G&A of $69 million was considerably below our guidance. As with prior quarters, this was primarily the result of the required quarterly mark-to-market of our cash settled stock-based compensation plans. Underlying G&A for the quarter was around $90 million, a little lower than average. Turning to the balance sheet, you will notice that our total debt increased $244 million to $5.5 billion in the third quarter as we utilize the revolver to partially fund the closing of the Texas Delaware Basin acquisition at the end of July. As we've discussed on prior calls, the revolving credit facility is an asset that can be utilized when attractive opportunities arise. We've demonstrated this over the past two years using the revolver to fund timely debt tenders, share repurchases, and asset acquisitions. Over time, we will look to pay down the revolver with available free cash flow that is not committed under the capital return framework. A few other things before we turn to Q&A. Please refer to our financial and operational supplement, which includes additional information related to our third quarter results, as well as our updated guidance for the fourth quarter of 2022. This can be found on our websites. 2022 will be a very strong year for free cash flow at APA. As John mentioned previously, at comparable prices, we expect to see increasing free cash flow in 2023. This excludes any financial benefit from our Chenier gas supply contract. At recent strip pricing, the anticipated benefit to 2023 would be around $570 million, assuming the latest possible start date of August 1st. which is a slightly later date than we have spoken of previously. One final note on U.S. income taxes. At this time, barring any contrary guidance that may be issued by tax authorities, we do not expect to be subject to the new 15 percent corporate alternative minimum tax until 2024. Thus, we currently anticipate no U.S. cash income taxes for 2023, as accumulated NOLs should more than offset projected taxable income. As always, please follow up with Gary and his team with any questions or if you need any other help related to our updated guidance. And with that, I will turn the call over to the operator for Q&A.
spk04: Thank you. As a reminder, to ask a question, you will need to press star 1-1 on your telephone. And due to time constraints, we ask that you please limit yourself to one question and one follow-up. Please stand by while we compile the Q&A roster. Our first question comes from the line of Doug Leggett with Bank of America.
spk05: Hey, good morning, everybody. Thanks for taking my question. Good morning, Doug. Okay, good morning, John. I got one on Suriname to kick us off, and then I'll go to one of the financial questions if that's okay. John, I realize that you've got a couple of wells drilling right now, but I'm also aware that Hess and Shell, I guess Shell as the operator, had a discovery that looks on trend, if I'm not mistaken, Zanderi, with your Awari prospect. So I'm wondering if you can characterize Awari what your expectations are, what the current status is, and whether I'm reading that right, that there might be some weed through from confirmation of a working hydrocarbon system. And I guess Hess has not really given any details as to whether that was a success or not, but it looks like they're reviewing it as we speak.
spk06: Now, Doug, the well we're drilling in the, you know, kind of the northwest portion of our block is Awari. You will remember Bonboni. It's 25 kilometers west of Bonboni where we found an active or working hydrocarbon system. It appears that they have a working hydrocarbon system north of us as well, so I think that's all good news. The big thing here will be TRAPP, but Tracy Henderson's here, and I'll let Tracy provide a little bit more color.
spk08: Morning, Doug. I think your comments are really spot on. You know, we are sort of up, dip, and trend from the Zanderi well. You know, we know as much as you do in terms of what's been in the public domain, but it sounds like, you know, a positive result, at least with respect to the petroleum system. So what this does do, you know, as John mentioned, we had seen Bonboni in the upper, or oil in the upper part of Bonboni previously. So what this does is basically push the mature proven kitchen further north into Block 42, so well north of our Block 58 northern boundary, which is good news for the petroleum system. And I would say it also increases the fetch area into Block 58 or the Block 58 northern prospects. I would counter that, though, with saying with these deepwater fans all along sort of that entire margin, the biggest critical risk factor is traps. So we will still need to, you know, be very focused on what our trapping geometries are. But from a petroleum system standpoint, if you have a working trap, this is good and it increases your confidence that you can charge them.
spk05: I hate to do a kind of part 1B, but just while we're on the topic of Suriname, do you have any color on Stapacharis South at this point, you know, as it relates to whether that can help inform an FID in 2023?
spk06: Well, a couple things I'd say, Doug, on Sopicar South. Number one, it's strongly supported from a seismic perspective, and it's an up-depth test of Sopicar South. Our operations are ongoing, and I'll say it could be a very material add to that area. So we're very excited about it in terms of you know, FID and so forth. We've got the appraisal at Sapa Car South, which is ongoing. We also have got appraisal at Crab Dago, which will follow, you know, sometime early next year. So we're excited about that, and we'll just have to get with you when we're ready.
spk05: Thank you for that. My follow-up is for Steve, and I guess there's, Steve, I'm going to try and, you know, layer in a couple of things to this, I guess, but Obviously, Chenier doesn't want to start this contract as early as you would like it to start. I think that's pretty clear given LNG prices. But I guess what I'm really trying to get to is your comments about free cash flow. You said, if I'm not mistaken, that the cash flow would be higher next year at a similar price deck, excluding Chenier, if I heard that correct. But you've also flipped this Waha strategy trading contract or gathering contract to kind of almost a $300 million run rate on revenues. So when you wrap all that together, it looks to us like the free cash flow could be up even at a substantially lower commodity deck. So can you help me understand if I'm reading that correctly?
spk14: Yeah, Doug, I think we're just going to have to be probably be patient to finish the planning process for 23. And we'll get to that in February, and we'll give all the details on that. But as John indicated, if we end up with a capital program that's kind of similar to where we've been running for the last two years, two quarters, which would be the $2 to $2.1 billion, If we allocate that similarly to the way we've been allocating and delivering activity for those last two quarters, if we end up in a price environment similar to 2022, then we will be up on free cash flow for next year. There have been some things that have changed a bit since the last time we talked about 23, which was in February. You know, we've got a little bit more activity that's leading to that increase in capital spending because we do have an extra rig in the Permian. We've got a couple of extra rigs going into 23 in Egypt. There are some new taxes, in particular the energy profits levy in the U.K., And there's talk now about possibly increasing the rate on that. We did say we don't believe we're going to be subject to the U.S. alternative minimum tax in 2023, and that would certainly be good if we could defer that until 2024. So there are, you know, and we've talked about, you know, the North Sea, perhaps being a little less predictable in terms of production volume, so having a wider range of possibilities. And we know that Egypt has gotten off to a little slower start in 22 than we had hoped for, and therefore that'll carry over a bit into 2023. So we've tried to be really transparent about where we are going into 2023 relative to the last time we talked about it in February. You know, we think we've got very good momentum. We're fixing some of the issues that we had in the second quarter. Certainly looks better in third quarter results and going into fourth quarter better. And I think we'll go into 2023 better. So a long-winded way of saying let's wait until February for the details on the capital program and the capital allocation and what that means for production volume. But we feel very good. We feel like the The plan that we laid out last February is still very much intact with the transparency of a few things that have changed since then.
spk05: I'll wait until February. Thank you, fellas, and we'll see you next week.
spk04: Thank you. And our next question comes from the line of John Freeman with Raymond James.
spk07: Good morning. Good morning, John. Just a follow-up on the last line of questioning. Definitely appreciate the early look on 2023, understanding that there's still some moving parts. But if I just wanted to kind of tack on to what you're saying, Steve, where if you're running kind of an aggregate in the U.S. and Egypt, it looks like on a year-over-year basis, maybe an incremental four and a half rigs versus what you did this year. Is there a way to sort of parse out of the 2 to 2.1 billion CapEx number how much of that kind of year-over-year increase is kind of activity-driven versus cost inflation?
spk14: Yeah, I'd say that, and John might have some comments on this as well, but, you know, I'd say look at the last two quarters where we've, you know, especially, you know, fourth quarter we're going to be running basically at what we're planning for for 2023. Preliminarily, most of that was the same in third quarter. We did have a bit of time where we didn't have the Ocean Patriot in the North Sea in the third quarter. But, you know, on the last two quarters, we've been running just a little under, or this last quarter and next quarter, we're running a little under $500 million a quarter, and that would give you $2 billion on an annualized spend rate. And so that's a preliminary view with maybe a little bit of inflation. built into that, you know, go into possibly 2.1. And, you know, that's just the preliminary view. We are still early days on the planning process, and I'd just caveat that with that could change. So let's wait and see in February. But I'd characterize it broadly as the bulk of the change in capital spending is because of the change in activity.
spk07: Okay, great. And then my follow-up question on Egypt, y'all did a really good job of playing catch-up, getting the completion cadence here in the second half of the year back up pretty meaningfully after the growing pains in the second quarter. But, you know, John, you mentioned that it's not totally behind us in terms of some of what y'all are going through in Egypt. Can you just sort of maybe give a little bit more color to what you're speaking to, because at least on a completion cadence, it looks It looks really good where y'all are going to exit the year in Egypt.
spk06: Yeah, we're in pretty darn good shape, but we've worked hard to get here in a pretty short time period. And a lot of it's just addressing manpower issues and training. And, you know, so we're in pretty good shape, John, and I think we're – You know, we're close to where we wanted to be, but, you know, you're still working through, you know, some things there. But we're in pretty good shape.
spk07: Great. Thanks, guys. I appreciate it.
spk06: Thank you.
spk04: Thank you. And our next question comes from the line of Neil Damon with Truist.
spk03: Morning, all. Thanks for the time, John. First question, a little bit on what Freeman was just asking, John. My first question is on production growth. Specifically, you all, I think, characterize 23 as potentially seeing, I think, what you deem as kind of moderate growth. But to me, looking at your 23 domestic and Egyptian activity plans, it seems like production could be even maybe a bit better than moderate. I know you don't have 23 guide yet, but I guess what I'm wondering is, is how you view sort of next year's contributions incrementally when you think about Egypt versus domestically, given, to me, all the domestic opportunities, including the new play there.
spk06: Yeah, I would just say, and Steve went into pretty good detail on that, an update of the early look on a three-year plan. And it's very dynamic, and we're working that. We'll come back in February. But in general, you know, you're still looking at, you know, mid-single digits on a VOE basis at the corporate level is what we're looking at. And that's going to be driven, you know, by oil in Egypt. You know, we should have cleaner run next year in the North Sea, although we're going to have a range. And then obviously we've had really good performance in the U.S., specifically in the Permian.
spk03: Okay, great details, John. And then secondly, just on shareholder return, I'm just wondering, would you all say you're still leaning in the stock buybacks? I guess what I'm trying to get a sense of that 1.6 buyback plan, what remains year-to-date?
spk06: I would just say, you know, I'll underscore we're committed to the returns framework. and we will deliver a minimum of the 60%. That's what I was hoping to hear.
spk03: Thanks, John.
spk06: You bet.
spk04: Thank you. And our next question comes from the line of Bob Brackett with Bernstein.
spk13: Good morning. I had a question on the Chenier gas supply contract. You mentioned the scale of a $570 million opportunity. Could you break that down for us in terms of the volume implied and maybe the price differential between Henry Hub and whether you think about TTF or JQM?
spk14: Yeah, Bob, so the contract is $140 million a day, and the $570 million, I won't recall exactly what day, but it's based on strip pricing. And we assumed an 80% TTF, 20% JKM mix, which we have the right to elect. And that was versus the same period strip for Houston Ship Channel. And then it has all of the deducts that we get from that contract for liquefaction, for shipping, for shrinkage, and for regas, and things like that.
spk13: Very clear. And that's sort of starting up in September? That $140 million a day is four months or five?
spk14: It would be five months. By contract, the latest that contract can start is August 1st. It could start earlier. I'm not holding my breath.
spk04: Got it. Thanks much. Thank you. And our next question comes from the line of Janine Y. with Barclays.
spk01: Hi. Good morning, everyone. Thanks for taking our questions.
spk06: You bet, Janine.
spk01: Good morning, John. Maybe we just go to the North Sea here. You mentioned in your prepared remarks lower and more variable run times just kind of given the age of the asset. Now we potentially have some higher EPL kind of overhanging here. The current 2023 outlook as it stands today is you said the North Sea activity should be consistent with 2022. But, you know, we're just wondering what the potential range of outcomes could be there, whether it's related to changes in the regulatory environment or by your choice. And we know it doesn't quite work like shale, but what kind of base decline is the North Sea on? Thank you.
spk12: Yeah, Janine, this is Dave Purcell. I don't have the numbers in front of me, but Think about the two different assets. We have 40s, which is a mature water flood. That's going to be on the base decline there. It's going to be on a high single-digit annual decline. These are high-water cut, low-decline wells. Barrel is a bit different. There's pressure maintenance through water injection. in many of those assets. But you'll see more conventional type declines in barrel. So they'll be higher than 40s. And so we can circle back and get to the blended number. But it's going to be somewhere in the mid to high teens, just based on memory. But we'll tighten that up.
spk01: OK, great. Thank you. And then maybe turning to the revolver, I think, Steve, you said you consider it to be an asset to utilize and there's attractive opportunities. You'll look to pay it down over time. You know, I guess our question is how much is too much on the revolver and how does this really factor into your appetite for future bolt-ons? Thank you.
spk14: Yeah, and I know our controller won't like me calling that an asset, but we view it as such in the non-accounting sense. And for that, it's for that very reason. We can, we used it for the bolt-on acquisition in July in the Delaware Basin. We use it for debt tenders. We've used it for share buybacks. In particular, we use it during periods where we have a period where we have no material nonpublic information. And we can use it for open market repurchases of shares and, you know, periods where we can be a little more selective at the pace at which we buy back shares during those periods of time. So, you know, so the revolver comes in very handy at those times. You know, we, especially with the price environment that we're in, we're pretty comfortable with the revolver where we've got it now and where it's been for most of the year. But we do need to get that paid down and preserve it longer term for that optionality around potential bolt-on acquisitions if we find the good opportunities.
spk01: Great. Thank you for the detail.
spk04: Thank you. And our next question comes from the line of Charles Mead with Johnson Rice.
spk02: Good morning, John and Steve and the rest of the team. Good morning, Charles. John, I... I'm hoping to get you to elaborate a little bit more your thinking on SapaCar South 2 and what kind of piece of the puzzle this might be. My understanding is you could drill appraisal wells in many locations, but you pick the location you do because you're hoping it will answer some questions for you and move you towards the you know, towards sanctioning projects. So can you talk about what the, what the, you know, the goals were with, with this location? I think you mentioned it's, it's up dip and, and how that could play into the, you know, moving the project forward in 23.
spk06: Yeah. The thing I would say, if you look at Sapa car South, it was a very, very high quality discovery. You know, you had the, 30 meters of pay, actually 32 meters full to base, low GOR, you know, around 1,100. And you had really, really high perm, 1.3 to 1.5 Darcy Rock. At the time of that, you know, we announced a connected volume, which we later updated to more than 400 million barrels. So, you know, Sapa Car South is really world-class rock. We also said at the time that we believe there was additional resource there that needed to be appraised, and that's exactly what this well is doing. It's moved up dip, and we are appraising, and we've got really, really good seismic support. We think the seismic is working, and it could add materially to that Sapakara South discovery.
spk02: Okay. Well, it would be interesting to... Catch up whenever you guys have the information to share there. And second question, I think this is perhaps for Steve, but maybe for you, John, and I think Neil was going at this a little bit earlier. Putting the pieces together, in your press release, you guys say that you're going to return at least $1.6 billion of cash in the form of dividends and buybacks. And then you guys had a... helpful slide in your presentation where you say you're at kind of you know one one right now and you've got it you've got another 130 actually you're at one right now and you've got maybe another 130 of uh of uh dividends are going to come forth to you so that if i'm doing the math right that's about 450 million uh for uh for the last or actually maybe you know maybe you did 80 million in in that but it's on the order of you know 400 million for november and december and that's a That's a big chunk. Are you guys going to have to enter in some kind of tender to get those shares in, or is this something you think you can do just participating in the regular daily bid?
spk14: Yeah, Charles, I'll just run quickly through the similar math that you were going through. We do expect now at recent strip prices that Free cash flow this year will be $2.7 billion, as John said. So that would imply a minimum committed returns of $1.6 billion. Year to date, we've done $127 million of dividends. We've bought back 26 million shares at $34. So that's $884 million of buyback. And as you said, that's just over a billion dollars so far this year. Since inception, by the way, that's 15% of the company that we bought back at a little over 31 bucks a share. So at 2.7 billion of free cash flow, that would imply for the fourth quarter total returns of 600 million. The dividends will be about 80 million, and so that implies buybacks of 520 million. And we've done right around 80 million of that in October. So your math was pretty darn close. All of that, if you landed right on 60%, would be about 440 million of additional share buybacks. Historically, we've delivered those buybacks through 10b51 programs and through OMRs. As I said, we use OMRs when we don't have material nonpublic information. We are drilling two wells in Suriname, so we do understand that situation and the risk associated with that. As John said, we're committed to that program, so you should assume that we have plans in place to make sure that that'll be delivered, because it will be delivered by the end of December.
spk02: Got it. So I appreciate you correcting my math, Steve, and it's kind of Wait and see, but you guys have a plan to get there, if I'm understanding correctly.
spk05: That's correct. We will get there.
spk02: Thank you, Steve.
spk04: Thank you. As a reminder, if you have a question, please press star 1-1 on your telephone. Our next question comes from the line of Paul Chang with Scotiabank.
spk10: Hey, guys. Good morning. Two questions, please. The first one is a little bit of clarification. John, when you're talking about mid-single-digit oil production growth for next year, is it based on the fourth quarter level or based on full year 2022 level? Because if it is based on full year 2022 level, that suggests that your next year oil production will be lower than the fourth quarter level. and with the increased activities and is there any reason why that the average production would be lower on the oil growth for next year than the fourth quarter level that's the first question and second one is really simple on the permian you say you're going to run five rigs but they include anything in the alpine high and then what's your view given the current commodity prices between the gas well and the oil rate as well. Thank you.
spk06: So, number one, 23 is a work in progress, so we're working on that. We said we'd come back in February. But in general, we said BOEs will be up mid-single digit. It's going to be driven by oil. And that is year over year, but we'll come back with that in details. That's really pretty much the shape of the three-year plan that we put out last February. When we look at the Permian five rigs, yes, today we've got two in the Midland Basin, three in the Delaware. There will be activity at Alpine High, and we do like the mix, and we think those wells compete very well today with where the gas price deck is and the oil price deck.
spk10: John, should we assume you're going to have at least one rig in Alpine High, or that is not necessary?
spk06: I would say today, just assume there's likely three in the Delaware, and Alpine High will be part of that program. Okay. Thank you. You bet. Thank you.
spk04: Thank you. And our next question comes from the line of Leo Mariani with MKM Partners.
spk09: Hey, guys. I was hoping to jump back to the North Sea here real quick. You know, just kind of looking at the production over the last, you know, couple years, certainly you guys have been hit with a lot of downtime there. You're forecasting, you know, higher production here, you know, in the fourth quarter. Just wanted to get a sense if there's, like, some things you're doing different operationally where you're kind of feeling more comfortable that you're going to be able to kind of deliver maybe some higher rates here going forward in the North Sea.
spk06: I'd just say a lot of it's the, you know, we're coming out of our maintenance turnaround season. And, you know, we've had to play catch up in 22 for 20 and 21. The COVID years hit pretty hard there, and we were limited on what we could do on the TARs. And you've just got aging infrastructure. And, you know, when things go down, it takes a little longer to get things back up. But, you know, I think we've got a lot of that behind us. And, you know, we will be guiding with wider ranges in the future. But, you know, right now we've got good momentum and things are running fairly smooth.
spk09: Okay. And just jumping over to Egypt here, just looking at your kind of gross oil volumes, I think those were down a little bit here. and 3Q versus 2Q. Can you just give us some indications as we get into 4Q and early next year? Do you think 3Q is the low point on those gross oil volumes when we start to have some nice growth into the end of the year? And then, what type of growth do you see in Egypt next year? Do you see that driving a lot of the overall production growth of the company?
spk06: Yeah, I think some of that's just timing of the well connections we had this quarter. And, you know, we've got good momentum really across the whole portfolio going into the fourth quarter. We're off to a good start. And, you know, we've had some wells that have come on and things. So we do think Egypt's going to be one of the big drivers in 23 and beyond.
spk09: Okay. Thanks, guys.
spk04: You bet. Thank you. And our next question comes from the line of David Deckelbaum with Catwin.
spk11: Thanks for taking my question, guys. I just wanted to ask, if I could, following up quickly just on North Sea, John, I think your comments were just on the aging infrastructure. Is there sort of a more of an outsized maintenance capex spend that goes into North Sea in 23? Is there an imminent need to upgrade facilities? And how does that sort of square with where production would be in the fourth quarter? Are we back to a more sustained level X downtime heading into next year?
spk06: I don't think it's any outsized. I think we really played catch up. in 22 and 23. There are always decisions that you make as you get into later years, like at 40s on equipment, and those are decisions we make routinely going forward. But those are all things you're constantly weighing the pros and cons of as you're looking at operating facilities as they get later in their life. But don't anticipate anything significantly outsized from normal, and we should be in a period of day with most of that behind us, you know, where things are going to run a little smoother. I appreciate that.
spk11: Maybe if I could just ask for a little bit more color on the Chenier contract. I think you all had marked today, based on the strip of pricing, Can you give us a sense on just how those netbacks work? Are the costs that are coming out of those LNG contracts on a fixed or variable basis? And what's a good ballpark to apply on sort of an MMBTU basis for costs relative to where the headline TTF price might be?
spk14: Yeah, unfortunately, it's difficult to give a kind of a generic approach to figuring it out because some of the costs like shrinkage and fuel and things like that will come out effectively at the, it's a loss of volume. So it comes out at the TTF and JKM price. And some of them are contractual dollar amount costs that do have some provision for inflation over time. So a good example of that would be the liquefaction fee. So it's not that easy to give a, kind of a generic rule of how it'll work through different prices of LNG or Houston Ship Channel for that matter. So that's why we just give it as a margin over Houston Ship Channel. Because I mentioned earlier in my prepared remarks that we actually sell all of our product that we produce in basin in the Permian. And we enter into pipeline contracts and things like that primarily as a participant in the industry to keep less liquid markers like Waha Hub more attached to the bigger, more liquid markets. And then we have a marketing organization that manages those contractual obligations. And for that reason, We look at the Chenier contract as a margin over purchased product because we will purchase product on the Gulf Coast and deliver that to Chenier. The pricing that we get is that net back calculation. And they buy the product. They take title to it at their plant inlet. So we don't have any title to product as it goes through their plant or the liquefied product as it comes out. We don't manage shipping or anything like that. We don't do the selling. They do all of that for us.
spk11: Thanks for the color there.
spk04: Thank you. And our next question is a follow-up from Doug Leggett with Bank of America.
spk05: I'm sorry, guys, for lining up again. But, John, I guess I'm listening to all the questions about the North Sea. I'm listening to the higher windfall tax risk, the less predictability. the life expectancy of the field, et cetera, et cetera. And I guess the obvious question to me seems to be, is this a core asset for Apache? Is there a point at which, whether it be, you know, you've got another core area in Suriname perhaps at some point, does the North Sea become surplus to requirements? Basically, is it for sale?
spk06: Yeah, I mean, the thing I would say, Doug, is that today North Sea is a core asset for us. Obviously, you've had some factors out there today that impact the ability to invest future, and you have to continually weigh in that. We benefit from the Brent pricing and the high netbacks and the free cash flow, but we also have a portfolio that is dynamic, and so you're always looking to expand your ability to invest in other assets. And as, you know, things change, sometimes out of your control, you know, it shrinks some of that. So, but today, you know, it is core, but it's something we're always taking into account as we're laying our future plans.
spk05: Appreciate it, John. Thank you.
spk06: Thank you.
spk04: Thank you. And I'm showing no further questions. So with that, I'll hand the call back over to President and CEO, John Chrisman, for any closing remarks.
spk06: Thank you for joining us on our call today. We started the fourth quarter with strong momentum across our global operations, which will carry into 2023. And sir and I, we're drilling an appraisal well at Sapakara South and an exploration well at Awari. We will share results when they are available. We remain on track to deliver on our capital returns framework. We will deliver at least 60% of 2022 free cash flow to our shareholders through dividends and buybacks. Our teams continue to work on our plans for the 2023 program and longer, and we look forward to providing more details to you in February. Operator, I will now turn the call back to you.
spk04: Ladies and gentlemen, this concludes today's conference call. Thank you for participating, and you may now disconnect.
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