Hi, welcome to APA Corporation's fourth quarter 2022 results conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there'll be a question-and-answer session. To ask a question during this session, you'll need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Gary Clark, Vice President of Investor Relations. Please go ahead. Good morning, and thank you for joining us on APA Corporation's fourth quarter and full year 2022 financial and operational results conference call. We will begin the call with an overview by CEO and President, John Christmann. Stephen 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 Pursell, Executive Vice President of Development, Tracey Henderson, Executive Vice President of Exploration, and Clay Bretches, Executive Vice President of Operations. Our prepared remarks will be approximately 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 fourth quarter and full year 2022 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 supplement information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interests 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 discuss today. A full disclaimer is located with the supplemental information on our website. With that, I will turn the call over to John. Good morning, and thank you for joining us. On the call today, I will review our key accomplishments in 2022, comment on fourth quarter performance, and provide an overview of our 2023 plans and objectives. Ahead of the pandemic in 2019, we established a pragmatic long-term plan for our business that emphasized returns-focused investment, strengthening the balance sheet, right-sizing the organization and activity levels to deliver moderate, sustainable production growth, conservative budgeting, and the selective pursuit of differentiated opportunities for value creation, most notably exploration. The world oil demand and commodity price dislocations that followed in 2020 and 2021 required some difficult and necessary actions to preserve our business. After a few years of hard work, we have returned to and are delivering on this long-term plan. In 2022, we generated the second highest annual free cash flow in the company's 68-year history, which we allocated primarily to debt reduction and cash returns to our shareholders. We also increased our rig activity to a pace that is now capable of generating sustained production growth in both Egypt and the U.S. Some of the more notable achievements of the past year include free cash flow generation of $2.5 billion, 66% of which was returned to shareholders. The repurchase of $1.4 billion of common stock at an average price of less than $40 per share, and the doubling of our annual dividend. A $1.4 billion or 23% reduction in outstanding bond debt. An increase in adjusted oil production from the fourth quarter 2021 to the fourth quarter 2022, which represents our first exit rate to exit rate oil production increase since 2018. The successful integration of our Texas Delaware Basin tuck-in acquisition, which complements our legacy Delaware position and continues to exceed expectations. Importantly, on Block 58 in Suriname, the flow test of two appraisal wells at Sapakara South, which indicated a combined resource in place of more than 600 MM bbl of low GOR oil. At Krabdagu, the discovery well was also successfully flow tested and appraisal is now underway with two rigs. Additionally, in Block 53, the first oil discovery was made at Baja, which is on trend with Krabdagu. Lastly, on the ESG front, routine upstream flaring in Egypt was reduced by more than 40%. This is a significant step toward our goal of eliminating 1 million tons of annualized CO₂ equivalent emissions by the end of 2024. Moving on to fourth quarter results. Following some operational delays in Egypt and unexpected facilities downtime in the North Sea in the first three quarters of the year, we ended 2022 on a strong note. Fourth quarter production and costs were in line with guidance, while CapEx for the period was slightly above expectations due to some small shifts in activity timing. U.S. production exceeded guidance on continued strong performance from our Midland and Delaware Basin oil properties. Oil volumes in Egypt strengthened as we continue to improve drilling efficiencies and project execution. North Sea production benefited from a substantial improvement in facilities runtime. Looking forward to 2023, we will continue to focus on managing costs and driving efficiencies while also taking advantage of the optionality within our portfolio to respond to commodity price movements. Specifically, with regard to the recent and substantial drop in natural gas prices, we are managing the portfolio for cash flow and not production volume. Accordingly, our growth in 2023 will be entirely driven by oil. We are reiterating our capital budget of $2 billion-$2.1 billion, which is consistent with what we indicated back in early November. We believe this appropriately reflects potential inflationary impacts for the coming year and remain confident in our ability to deliver within this range. At this investment level and assuming current strip prices, we anticipate year-over-year Adjusted oil growth of more than 10% and BOE growth of 4%-5%. This is consistent with the preliminary BOE guidance we discussed on our November call. Oil volumes in Egypt and the U.S. will be the primary contributors to growth, more than offsetting a decrease in natural gas production in both regions. As we also noted on our November call, we are expecting a sequential decrease in U.S. production from fourth quarter to first quarter. This is primarily driven by our Permian Basin oil well completion cadence. Natural gas curtailments at Alpine High and liquids volume reductions associated with ethane rejection during the month of January are also significant contributors. Importantly, our Permian oil well completion cadence will accelerate in the second half of February, which should lead to significantly higher U.S. oil production in the second quarter through the fourth quarter. Turning to the North Sea, we anticipate a moderate production rebound this year, with three new wells coming online in the first half and shorter scheduled maintenance turnaround times. We plan to release the Ocean Patriot semi-submersible drilling rig around mid-year following completion of a scheduled drilling campaign in the North Sea. The permanent reallocation of this capital to other areas is being evaluated as the recent tax changes in the U.K. have made returns less attractive than other investment opportunities within our portfolio. In Suriname, first half 2023 activity is focused on the two appraisal wells drilling at Krabdagu and subsequent flow testing. Following that, another exploration test on Block 58 is also planned. While average oil and gas prices are trending down relative to 2022, APA's free cash flow this year should be bolstered by our gas sales contract with Cheniere. Stephen will provide more detail around the expected impact of this contract in his remarks. We remain fully committed to returning at least 60% of our free cash flow to shareholders through a mix of dividends and share buybacks. Strengthening our balance sheet also remains a priority. We anticipate that most or all of the free cash flow not returned to shareholders will be used to reduce debt. In closing, while the industry is experiencing considerable short-term oil and gas price volatility, we have a constructive outlook on the long-term supply and demand for hydrocarbons. Over the next several years, our plan is to maintain a relatively constant activity level, yet remain flexible to shift capital within the portfolio to the highest value opportunities. Through the cycle, we also plan to continue allocating an appropriate percentage of our capital budget to high-quality differential exploration opportunities. APA's investment case and portfolio are unique. Within the Permian Basin, we can allocate capital investment to oil or natural gas and generate growth from either or both commodities. Additionally, we hold considerable long-term gas transportation capacity, which our marketing team utilizes to purchase and resell third-party gas for a profit. We have gas sales to Cheniere commencing this summer that will provide long-term access to international index pricing. Our Egypt operations offer exposure to premium Brent oil prices, modernized PSC terms, and an opportunity to generate consistent growth in an area with tremendous potential. In Suriname, our joint venture partnership enables the appraisal and potential development of large-scale projects on Block 58 with limited capital investment. We believe APA is well-positioned to help profitably deliver hydrocarbons that the world needs for the next decade and beyond. We are committed to doing this while reducing carbon intensity and being good environmental stewards. With that, I will turn the call over to Stephen Riney. Thanks, John. APA delivered very good financial performance in the fourth quarter and for the full year as we benefited from a strong, albeit volatile, price environment. For the last three months of 2022, consolidated net income was $443 million or $1.38 per diluted common share. As usual, these results include items that are outside of core earnings. The most significant of these items was a pre-tax charge of $157 million to increase the net contingent liability for decommissioning the former Fieldwood properties in the Gulf of Mexico. The increase reflects a combination of changes in cash flow during the life of the producing assets and estimated future decommissioning costs. This was partially offset by a $52 million pre-tax unrealized gain on derivatives and a $47 million release of a valuation allowance on deferred tax assets. Excluding these and other smaller items, Adjusted net income for the fourth quarter was $476 million or $1.48 per diluted common share. During the fourth quarter, APA generated $360 million of free cash flow and repurchased more than 12 million shares of common stock, resulting in approximately 312 million shares outstanding at year-end. Underlying G&A costs for the quarter remained around $95 million. Total G&A was $169 million, which was above our fourth quarter guidance. This was caused by an increase in anticipated incentive compensation plan payouts, as well as the recurring mark-to-market for previously accrued stock-based compensation that will be paid out in the future. These accruals also resulted in higher than expected LOE and exploration expense, though to a much lesser extent than G&A. Exploration expense was also elevated as we recorded $66 million of combined dry hole costs for the Awari prospect in Suriname and a non-commercial exploration well in the North Sea. Looking ahead to 2023, as John outlined, we expect continued production growth and strong free cash flow generation. At 2022 prices, free cash flow in 2023 would be about the same as 2022. Growing production volumes and cash flow from the Cheniere Gas sales contract at current strip prices would offset the impact of higher taxes in the U.K. and the increased capital program. We will once again return a minimum of 60% of free cash flow to shareholders through share buybacks and dividends, with the remaining 40% primarily used for reducing net debt. The gas sales contract with Cheniere will commence in the second half of 2023. We entered into the agreement in 2019 with the purpose of aligning aggregate financial outcomes with a more diversified portfolio of gas prices, similar to the diversified oil prices we enjoy naturally through the portfolio. We are frequently asked about the contract's expected free cash flow and its sensitivity to movements in U.S. gas and global LNG prices. At current strip price levels, we project roughly $200 million of free cash flow contribution in the second half of 2023. If you want to put a range on annualized forward-looking free cash flows, let me give you two potential outcomes as realistic end posts. Assuming average prices of $20 LNG and $4 Houston Ship Channel, the expected annualized free cash flow would be approximately $500 million. Assuming higher average prices of $40 LNG and $6 Houston Ship Channel, the annualized free cash flow would increase to approximately $1.25 billion. It is important to note that these cash flow numbers include the costs incurred to purchase the gas to supply to Cheniere. We believe there is substantial upside price exposure. Despite this, we will continue to plan and budget conservatively, given the volatile gas price environment and the scale of associated changes in the cash flow profile. Turning now to income taxes. The U.K. recently increased its Energy Profits Levy from 25%- 35% and extended the effective period through March 2028. The combined statutory tax rate in the U.K. for 2023 is now 75%, and we expect this will be fairly close to our effective tax rate as well. With that, at current strip prices, we expect U.K. current tax expense of $550 million-$575 million this year. In the U.S., we do not expect to be subject to the 15% Corporate Alternative Minimum Tax in 2023 and therefore anticipate no current federal income taxes for the year as accumulated tax losses more than offset projected taxable income. Please consult our financial and operational supplement for a full suite of guidance items for both first quarter and full year 2023. To wrap up, 2022 was a year of great progress as we exceeded our minimum shareholder return commitment and significantly improved the balance sheet. We reduced outstanding bond debt by $1.4 billion, while also returning 66% of free cash flow to shareholders and restoring the base annual dividend to $1 per share. Through the buyback program, we repurchased 10% of the company's outstanding shares at an attractive average price of roughly $39 per share. In 2023, we anticipate another strong financial performance with more share repurchases, more balance sheet deleveraging, and more progress toward our objective of achieving an investment-grade rating with all of the rating agencies. We look forward to updating you as the year progresses. With that, I will turn the call over to the operator for Q&A. Thank you. As a reminder, to ask a question, you'll need to press star one one on your telephone. To withdraw your question, please press star one one again. Please wait for your name to be announced. Please stand by while we compile the Q&A roster. I'll now turn the call over to Mr. Gary Clark. Thanks, operator. One quick administrative note. Stephen Riney will not be available for Q&A as he unfortunately needs to attend to a family matter. Ben Rodgers, our Senior Vice President, Treasurer, and Head of Midstream and Marketing, has joined us, and he will be able to address your questions related to financial topics and gas marketing and transportation. We'll give it back to you, operator, for the Q&A. Thank you. One moment for our first question. Our first question comes from the line of John Freeman with Raymond James, your line is now open. Good morning, guys. Good morning, John. First topic, just looking at Egypt, obviously, really solid quarter in 4Q. Nice to see the rig efficiency gains. I was looking at the success rate that you had in Egypt in 2022 versus the prior couple years, and the success rate was meaningfully better at about 85% average in 2022. I guess I'm trying to get a sense of how much of that is maybe related to some of the seismic you had done a year ago or anything else you're doing in Egypt that would maybe indicate that higher success rate is sustainable going forward? Yeah, John, I'd say the program's been pretty constant. You know, we drilled really, you know, a multitude of different well types, both on the development side and the exploration side. I think what you're seeing there is, you know, the impact from the modernization. There were some things that were not being pursued because of the modernized terms, and we were able to pull, you know, some of those forward and prioritize them. You're running a little higher on the success rate, as we get some of that low-hanging fruit, initially. Great. Follow-up on looking at Suriname. Has the exploration well been identified where that'll be after the two appraisal wells? Is the entirety of the 2023 plan, the two appraisals and the one exploration, which was kind of laid out in the presentation? Are we supposed to think of it as you do the appraisals and then it's sort of a let's see what comes of that and then determine the second half of the year sort of plan? Just a little bit more detail on Suriname, please. Yeah, I would just say today we've got the, you know, the two appraisal wells that we're drilling at Krabdagu, and that's, you know, gonna take a good portion of the first part of the year, and that's where the priority is now. we do have, you know, one exploration slot that is still being worked, and we're still debating with partner on, you know, which well that will be. there are multiple wells identified. It's just a matter of which one. for now, that is the plan. you know, obviously we'll readdress that throughout the year. Great. Thanks, John. Thank you. Thank you. One moment for our next question. Our next question comes from Jeanine Wai with Barclays. Your line is now open. Hi. Good morning, everyone. Thanks for taking our questions. You bet, Jeanine. Morning, John. Our first question may be just keeping along with John's on Suriname. The estimate for resource at Sapakara is now over 600 MM bbl of oil in place. I guess our question is, you know, what's the confidence level of that estimate and how much overall resource is required to get a project to FID? We know you're doing a ton of appraisal at Krabdagu this year as well? Yeah, I mean, in terms of the estimate at Sapakara, you know, there's good confidence. You know, we flow tested those volumes. It's really high-quality rock. It's low GOR oil and really got one, you know, main sand package. It's gonna have a high recovery and, you know, it'll be a big key component, you know, potentially of a future project. We have great confidence there. Then we've got, you know, the two appraisal wells that are being drilled at Krabdagu right now. In terms of, you know, development size and so forth, as we've said, we're working towards a, you know, first project. You know, really right now it's premature to talk about anything, you know, pending the results of appraisal at Krabdagu, which we're very excited about. you know, it's moving right along. We'll stay tuned for those appraisal results. Maybe moving to the U.S. You mentioned in your prepared remarks that you're managing the portfolio for cash flow and not production, 2023 is driven by oil this year. You also curtailed some Alpine High production in January. Can you provide any further color on what the price sensitivity is of natural gas curtailment at Alpine High? Thank you. This is David Pursell. It's a good question. You know, our curtailments earlier in the year were relatively small. When Waha, you know, Waha's had a lot of volatility, so as we get down to low Waha basis and, you know, sometimes it's going negative, so we're making those decisions, you know, daily and weekly. It depends on dry gas versus wet gas. There's a lot that goes into it. As we look at it now, we've been flowing Alpine full out through most of January and February. Not gonna give you a specific price marker, but we're looking at it in pretty extensively every day and every week with the marketing team. Thank you. One moment for our next question. Our next question comes from Charles Meade with Johnson Rice. Your line is now open. Good morning, John, to you and the whole APA team there. I wanna ask a question about the Krabdagu appraisals. I recognize that, you know, we still have to get the important data that those appraisals are designed to get, with, you know, not just what you see on the logs but with the flow test. From my seat, and I think from most of the people outside looking in, you guys have, you know, you're about to have two appraisals ongoing. It really looks like you guys are trying to drive, you know, to get the data to get to a decision point in the near term. Is that a fair inference to make? I mean, Charles, we've prioritized the appraisal at Krabdagu, right? You saw us move at, from Sapakara with two appraisal wells there. We're very pleased with those results. You know, Sapakara 2 kind of came in as we had projected and modeled. You know, obviously anxious for the results at Krabdagu. You know, it is fair to say, and it's fact, we've prioritized the appraisal, you know, program right now. Right. Thank you for that, John. That's where I was, where I was trying to get to. The second one, just quick follow-up for me. How would you set our expectations on when we're gonna hear about the Krabdagu flow test? You know, both at the same time or what should we be thinking about? Charles, I would just say that, you know, clearly one of the wells is ahead of the second. You know, the second one is better on location, spudding any time now. There, there will be a lag. We'll just have to see what we decide to do and work with TotalEnergies in terms of what we come back with in timing. You know, we're moving on both of those as quickly as possible, and it's very important information. Thank you. One moment for our next question. Our next question comes from the line of Paul Cheng with Scotiabank. Your line is now open. Thank you. Good morning, guys. Good morning, Paul. Couple of questions. John, can you remind us that what is Alpine High, role in your longer-term portfolio? I think at one point several years ago, you sort of write down everything. Then, gas probably become a little bit better, and I think you guys, go back and sort of having. Seems like it's having a role in the long term. How should we look at the Alpine High? Also the second question is that, I think, you guys have not done any bolt-on acquisition, in the last, 12 months, 18 months. Some of your peer has done so. How should we look at bolt-on acquisition for you guys, over the next two or three years? Is that a, could it play a reasonable role or that you will be focusing more of your effort in exploration, like in Suriname, and also that the activity level with Egypt? Thank you. Two really good questions, Paul. I mean, the first thing I would say is, Alpine High is a, you know, is a nice piece of our Permian portfolio, and we look at it as part of the Delaware Basin. It's one of the levers we have the optionality to allocate capital to. We've got, you know, really three wells that we're gonna be bringing on, you know, during the first quarter. Then you'll see a, you know, kind of a break, and then we've got, you know, five wells that'll be coming on year-end. It is something we can toggle and, you know, we'll tend to leverage that. What you've seen is this year is, you know, given the weakness in Waha and U.S. gas, there's no reason to be bringing on incremental volumes. But it's really about prepping for the opportunity and having that optionality, you know, when you look at 2024 and beyond as some of the basin bottlenecks open up. You know, it'll be a toggle for us, and it's a place we have the optionality to invest, and we plan to use it as such, and that's been the, you know, the game plan. I think when you step back, and your second question related to bolt-on, you know, acquisitions, we did do our first acquisition, you know, last year in the Delaware, a very nice tuck-in acquisition. You know, it was one that, you know, we're, we're constantly in the market looking at things, as is, you know, we have assets in the market. We typically wait to talk about things until there's a transaction or something to do. You know, the tuck-in we did last year is something that's been exceeding our, you know, our acquisition forecast, something we're very happy with. You know, it's now integrated into our Delaware package, in our, you know, our Delaware assets. I think it's something you just got to monitor. I mean, if, you know, you've got a handle on your current inventory, you've got a handle on, you know, costs. If there are things that we think we can add at attractive, costs where we can, you know, drive incremental returns, then we're not opposed to doing that. It's been a high bar, and that's why we've really only done one transaction over the last couple of years. You know, we're gonna continue to drive a balanced portfolio. We are emphasizing exploration with the program we've got in Suriname. You know, we also do a lot of, you know, just blocking and tackling things elsewhere or, you know, around the globe. Thank you. One moment for our next question. Our next question comes from Doug Leggate with Bank of America. Your line is now open. Hi, John. Good morning. Good morning, everybody. Good morning, Doug. John, I've tried this a couple of times in the past, but I'm gonna try it again. Suriname, recovery factors, given your porosity, permeabilities, world-class rock, obviously. Can you give us some idea what you think that looks like? If I may reference the more than $800 million as opposed to the $600 million, it looks like we're heading to a joint potential Sapakara, Krabdagu development. What should we think in terms of timing and scale of an FID? Great question, Doug. You know, there's a lot of work we've done, and we have a lot of confidence in what we've put out, but there's also a lot of work, you know, left to do. I will talk about, you know, give you a little bit of color on Sapakara, and then I'm gonna, you know, bring Dave in if he wants to add anything. You've really got, you know, two areas. You are correct. We are, you know, we are working towards, with our partner, potentially a development hub, where you'd be bringing in, you know, both Krabdagu and Sapakara. They are a little different in terms of the makeup and so forth. You know, Sapakara is predominantly one package. Really high quality rock. When you're talking low GOR oil, you know, 1,100 GOR oil and you're talking 1.3-1.5 darcy rock, one nice blocky sand, you're gonna have high recoveries. That's really all I'll say at this point. You'd wanna get into FID study and do, you know, more work before we come out with more specifics there. Some of the questions you're asking are things that will come later. Krabdagu is, you know, there's three targets there. It is the, you know, the incremental 200 that, you've referenced there, and we're in the process of appraising that. You've got a range of, you know, GORs there depending on the zones. The work we're doing to, you know, understand those and quantify those is really important to, you know, determining potential scale and scope. You know, all things underway. We prioritize it, which is why you've got two rigs there. You know, we're anxiously awaiting those as well because it's gonna, you know, have an impact on scope and scale. Thank you for that, John. I guess we're not gonna get the FID timing question, but I told you I would try again. You know, I'm torn as to whether I ask my second on Suriname as well. I think I'm going to, so let me try this. Did you find an oil water contact on the second appraisal well at Sapakara? I guess what I'm really trying to think of, you know, the focus obviously is on these two, but there's still, if I recollect, multiple playbacks, multiple years left in your exploration program. How do you think about the broader risk of the basin at this point? Oil window, obviously prospect-specific risk and so on. Just generally characterize it for us. Is this gonna be one and done, or do you see capacity for a longer-term exploration development program in the basin? Well, you know, bunch of questions in there, so I'll try. Sorry. I'll try to answer all of them to the extent I can. You know, one, Sapakara South 2 was an up-dip appraisal. I think that was important in terms of confirming, you know, what we confirmed there. If you go over to Krabdagu, I'll remind you, Baja, in Block 53 was a discovery of a down-dip lobe in that Krabdagu fairway. You know, there are multiple levels, and that's part of what you're, you know, you're driving at. You know, there's also a pretty good chance we're appraising up dip at Krabdagu as well, which is always a good thing when you're appraising. We see a lot of potential. I mean, if you look at where we are today and the area we're working, we've had great success. You know, there is more beyond just Sapakara and Krabdagu that could also go into a potential hub. If you look on the outboard side of the block, you get further out. You know, we've had a working petroleum system, and we found hydrocarbons. The trick's been, you know, trap and seal as you get out there. You know, I do believe we will have an ongoing program in Suriname, as there is a lot of prospectivity. Thank you. One moment for our next question. The next question comes from the line of Neil Dingman with Truist. Your line is open. Morning, John. Thanks for the time. John, my first question, really just a broader one on shareholder return or specifically maybe capital allocation. The last couple of quarters, you all were pretty adamant about talking about maybe a minimum amount of buyback given still, you know, what I certainly agree with, a cheap stock price. I'm just wondering, you know, do you all still feel like that? I mean, do you have kind of a minimum level that you think about going forward for this year, this quarter? I mean, I'm just wondering from a shareholder or buyback perspective, if you're able to frame anything up. No, I think we have, you know, good question. We have great confidence in the framework we put forward. I'll underscore when we say on the buybacks, we'll do a minimum of 60%. As you know, you saw last year, we were able to execute on that. You know, we feel strongly about it today as well. They, you know, that's what you'll see us do. By nature, things were back-end loaded last year just because of the volatility in the commodity price. You know, we were active, I think, in 10 out of 12 months on the buyback. You've seen us taking similar approach this year, but, you know, it is definitely a minimum of 60% that gives us ample on the additional 40% to, you know, address balance sheet. You know, yes, I'll underscore that. No, great point. Okay. Really just a second question on domestic activities. It's It's been asked a little bit, but I'm wondering, you know, you all mentioned having the two Southern Midland Basin, the three Delaware rigs. How fluid is this? Could this change depending on prices? Or even more activity in that newer Titus area, just wondering for plans remainder, maybe more second half of the year? Yeah, I would just say we're in a really good cadence in the Southern Midland Basin, and you're seeing it in our results because we're, you know, we're planning pads, you know, way down the road, and it gives us time to really execute and think about how to maximize the NPV and, you know, the returns. That 2-rig program's been a good cadence for us at Southern Midland Basin. We've got three in the Delaware, and that's where there's flexibility. And, you know, you've seen from the forecast, we're shifting those more to the oil-weighted projects in the Delaware, and that's the luxury we have of, you know, of our portfolio today. Then we've integrated Titus in, so it's really just part of our Delaware program. And, you know, it's ours, so. Thank you. One moment for our next question. Our next question comes from the line of Roger Read with Wells Fargo. Your line is open. Yeah, good morning. Good morning, Roger. Morning. happy to finally show up here. One quick question for you on your comments about the outlook for the agreement with Cheniere, the range of 500-1.25. When we look at it between, you know, the ship channel price and the European price, which one do you see more sensitivity to? In other words, we see a big move in prices here or a continued, you know, slump here, and big moves, we've set continued volatility over in Europe is, you know, which is the weighting towards? It's gonna be more on the, you know, the global element, you know, TTF or JKM. I'll let Ben, you know, provide any additional details. No, that's right. I mean, there's a lot of variables that go into it. We've seen weakness in the, in the ship channel this year, mainly from Freeport LNG being offline and just generally milder weather. A lot of domestic variables that are impacting the Houston Ship Channel. To John's point, you know, with the war in Ukraine and a milder winter over in Europe, I think it was, you know, only the second or third warmest winter that they've had over there in close to 50 years, it's just going to insert a lot of volatility there. The good thing, though, as we look at it, you just kind of step back. We think it does provide a very significant potential uplift to our free cash flow numbers. You know, we have that inherently on the oil side by selling our North Sea and Egyptian oil barrels at Brent-based pricing. It's one of the reasons we entered into this contract in 2019, was to get access to the global gas market as well. Yeah, it makes sense. The follow-up question I have is, understand the reason for reducing investment in gas in the near term. As you look at your, let's call it guidance goals, expectations to deliver oil volume growth this year, what should we be paying attention to as the risk factors on that? You know, things that, which, I guess, could cause you to come in underneath, or any of the other issues, as you mentioned, kind of like, you know, well cadence, stuff like that? I mean, it's exactly those things, Roger. I mean, we've got good confidence in the program, you know, it's underpinned by, you know, two onshore areas with Egypt and Permian. You know, but it will be that very thing. It's the, you know, the turning lines and the timing. You know, you're seeing that a little bit with the first quarter because we only had four wells in the U.S. You know, fourth quarter of last year, and they were late, one Permian, three Chalk. A lot of that's gonna be driven by the function of just the, what's the timing on the execution. When you're running, you know, five rigs in the U.S., it's gonna be lumpy. Egypt, it took us a little bit of time to kind of get our legs under us with the 17- rig program. I mean, those are the key things to watch. Thank you. We have good confidence in our projections. Thank you. Our next question comes from the line of Neil Mehta with Goldman Sachs. Your line is now open. Yeah, thanks so much. Maybe, John, the first question is around capital efficiency. The spend budget came in a little bit lower than where consensus was. Maybe you could talk about what you're seeing real-time, both international and in the U.S. in terms of inflation. You've seen any green shoots that this period of immense inflation is starting to move back into your direction? Yeah. Neal, a good question. I would say we spend a lot of time trying to stay about a year ahead of our programs with our contracts and things, because that gives us, you know, the visibility in terms of the spend. Today, a lot of what you're seeing is, you know, contracts based on, you know, the back half of last year's pricing. I think it's a little premature, you know, from our perspective to be seeing any softness tied to the commodity price. I think if the price stays where it is today, that is one of the upsides of the plan, is you're gonna see cost structures, you know, follow. They just tend to lag, they will follow the decks. It just takes a little bit of time to play catch up. You know, nothing there to really comment on in terms of green shoots or anything at this point. Yeah, that's fair, John. The follow-up is the North Sea. Maybe talk about the impact of the 75% tax rate. How it's affected, your willingness to invest in the region. There was obviously the Ocean Patriot release as well. Any comments you have around tax rate broadly would be helpful. Yeah, I would just say that it's made the North Sea less competitive relative within our portfolio. You know, as we look at that, still an asset that, you know, we're gonna manage for cash flow. You know, we'll get good performance there, and we're gonna continue to invest in, you know, asset integrity and maintenance and, you know, all the things we need to do environmentally, safety, like we always will. You know, longer term, incremental dollars that we have alternatives to put in other places, you're seeing us, you know, make that decision just because there's more attractive places to put that. It's made the North Sea less competitive on a relative basis within our portfolio, and that's why you're seeing us, you know, drop the Ocean Patriot rig, you know, later this year. Thank you. One moment for our next question. Our next question comes from the line of David Deckelbaum with Cowen. Your line is now open. Hey, John. Thanks for the time today. You bet. Just wanted to ask on sort of the future expectations for Egypt growth. I know since the modernization of the PSC and the ramp up to 17 rigs now, the view was that this could be sort of a multi-year growth opportunity. you know, I understand the beginning of this year, you know, production obviously declines and then ramps throughout the year. It seems like a combination of till cadence, but also just curious if there's infrastructure challenges driving some of that production curve. Then what we should expect, you know, once we're 10% higher in the fourth quarter of 2023 going into 2024 and beyond there? I think you'll see, you know, a pretty robust program in Egypt. The thing you have to recognize there, we've got two factors going on. You have a big, you know, discovery that was predominantly gas and that's, you know, starting to decline. That's why you're seeing the oil growth, which is where the drilling program with the 17 rigs are focused in Egypt. You'll see that oil mix is what's growing in Egypt as well, and that's what's underpinning that program. You know, it's an onshore, you know, multi-rig program. You know, it's a little bit different from the unconventional that you're, you know, folks have gotten used to in the, in the U.S., where it's shale and you can do pad math. You know, the nice thing is this is conventional rock that flows at you pretty hard and fast and sets up, you know, smaller developments, but very impactful material developments. you know, good confidence in the long-term curve there. We've been in Egypt since 1994 and, you know, a lot of good confidence in that. I appreciate that, John. Just my second one just on Suriname. It sounds like we're obviously waiting for the appraisal results from Krabdagu and the intention to potentially build out a hub there. I guess, does that necessarily preclude, you know, Sapakara being developed independently? Would you view this as, you kind of need to combine both Sapakara and Krabdagu into one hub system to maximize economics and that Sapakara wouldn't necessarily support a development on its own? You know, I'll just say your, you know, both us and our partner are motivated to, you know, to get the scope and scale correct from the get-go. You know, the larger the project, the larger the boat, the better the economics are gonna be. You know, there's no reason to try to get into, you know, you know, could you? Because what we're really looking at is how do you get the scope and scale right, and that's why we're looking at, you know, trying to combine these. Thank you. One moment for our next question. Our next question comes from the line of Leo Mariani with Roth. Your line is now open. Hi, guys. I was hoping you could talk a little bit more about the North Sea. Obviously, you're making the decision to drop the rig here, you know, later this year. You know, it certainly sounds like that tax rate is gonna be significantly high for quite a few years. You know, should we expect the result of that rig being dropped? Is it gonna kind of accelerate some of the production declines? Should we expect to see, you know, kind of steady declines on asset maybe starting in 2024 and beyond? Just trying to get a sense of what the ramifications are of the less activity. I would just say in general, it doesn't really change the, you know, the abandonment time frames as we model that out today. Really, you know, you look at this year, not much impact from the Ocean Patriot. It was drilling some things that are bigger impact, sub-sea wells that, you know, take time to come into play. It does have an impact. You know, start to see a little bit in 2024, 2025 and beyond. It doesn't really drive. I mean, we're still, you know, looking at early 2030s for both Forties and Beryl. You know, when we bought the Forties asset, I'll go back and remind you when we bought that in 2003 from, you know, BP, it was scheduled to come out of the ground in 2012. Here we are, you know, more than a decade longer, 12, you know, 10 years, 11 years longer, you know, still looking at, you know, close to another decade. There's still good productivity and life there. We're just gonna manage it, you know, for cash flow and be very prudent about, you know, the future investments. That's helpful. Just jumping over to the U.S. just wanted to get a sense, is there anything at all planned in the Austin Chalk in 2023? I know you guys had some wells that kind of came on, you know, late last year. If there's any update you have on that asset. Also just to follow up on Alpine High a little bit, do you guys really, you know, it sounds like you're kind of viewing that as somewhat of optionality on the gas market in the next several years, and then hopefully that gas market will improve. You know, do you guys have long-term designs on using Alpine High as a feedstock for some of these Gulf Coast LNG facilities? I mean, the thing I would say is, you know, recognize the, you know, the contract with Cheniere is a separate deal. It's a corporate-level deal. We buy gas and, you know, ship channels. It's separate and aside from what, you know, our equity gas that we produce. You know, we sell that in basin at Waha, and prices at Waha are gonna dictate what we do in basin. You know, that's the point to make there. In the Chalk, we brought on those three wells. Today, we don't have anything planned in terms of drilling from a working interest perspective in the Chalk. There may be some non-op wells we participate in, you know, where we've got some non-op interest there that others are drilling, but, you know, nothing planned in, you know, our budget this year for Chalk drilling. Thank you. One moment for our next question. Our next question comes from Arun Jayaram with JPMorgan Chase. Your line is now open. Yeah, good morning. John, the more recent activities in Suriname have been focused on appraisal activity with, I guess, two rigs now on location at Krabdagu. What are you and the partners' plans in terms of incremental exploration, you know, post the evaluation results of Krabdagu with the two rigs? There will be another exploration well drilled, Arun, and we're still working on that location. Between us, there are several prospects. you know, both teams are spending time high grading. I mean, you know, if you go back and look at both Awari and Bonboni in Block 58, we have working petroleum systems, hydrocarbon systems out there. you know, the main targets in both cases failed because of breach of seal. you know, I'd say teams are spending time, but there is a lot more prospectivity. You know, to the outboard side all the way back into the where we've had great success. Working through that with our partners and, as we, you know, get in a position to drill more wells, we'll talk about those as they come onto the rig lines. Got it. Just maybe one follow-up in the Permian. John, as I think about your 2022 program in the broader Permian, including in 4Q, you know, the company didn't place as many wells onto sales as we would have thought in terms of our modeling. You know, looking at 4Q, I think you placed 1one or so wells to sales. What drove that in 2022? Were you building some ducks? You know, just thoughts on how, you know, will that shift a little bit as we think about 2023 because you have a pretty robust, you know, production growth outlook from the. No, Arun, it's a great question. I mean, it's really more just the lumpiness of a program. You know, we're drilling longer laterals, and you've got two rigs in the Midland Basin. A lot of it's just the timing of the pads, completing the pads, and then working through the completion, you know, timing. With only two rigs, you know, you're gonna see lumpiness from us, whereas if we were running a lot more rigs then that lumpiness kind of starts to, you know, work itself out and normalize. It's really just a function of timing on those with longer laterals. Thank you. One moment for our next question. Next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering. Your line is open. Hey, good morning, everyone. Appreciate y'all taking my questions. Just got a couple here. You bet, Jeoffrey. Yeah, thanks for squeezing me in. Just a couple here, follow-ups on Egypt. Obviously, some solid execution there, especially relative to earlier in 2022, as y'all highlighted. That's showing up in production results as we all saw. As we think about the 2023 guide, I was hoping you could speak to, you know, how you're thinking about the level of conservatism or risk that might be baked in there as you think about the oil growth exit to exit. You know, what kind of running room you might see from here on operations and efficiencies as we move through the year and what we're focusing on, in terms of, you know, tracking execution, from here on the 2023 program? Well, I mean, Jeff, you know, question, we obviously try to guide to what we believe are, you know, numbers with high confidence that we can hit, and we spend a lot of time on that. You know, I do believe there are things at times that, you know, the nice thing about Egypt is, there is ability to, you know, with success, to bring other things on and get other wells drilled and high grade that schedule as you're moving through the year. You know, I think we've given very realistic and good guides, you know, for 2023. I think there's good confidence from the team. I know I sure ask that question, and it's the response I get and the response that I'm, you know, comfortable to relay. Okay, great. I guess just on operations and efficiencies, again, you know, obviously improved quite a bit as you move through 2022. Just wanna get a sense for what you're focusing on from that perspective and, you know, what kind of running room you might see for improvements from here? You know, it's all about operational excellence and continuing to try to improve and, you know, learn from things as you go. You know, in Egypt, we're drilling in some new areas with, you know, with the seismic and some of the exploration that we're doing there. Within those areas, we should see improvement as we drill more wells, and, you know, areas you've drilled before. You know, you're seeing some of that. You know, the big thing is, you know, across the entire organization, across the asset teams, across the functions, you know, everybody is really trying to take all the data, integrate it, and get better. I mean, it's about continuous improvement and, you know, execution excellence. You saw great progress on the safety front. We're gonna continue that and, you know, continue to focus on the operations. Paying attention to details. Thank you. I would now like to hand the conference back over to Mr. John Christmann for closing remarks. Yes, thank you. Before closing today's call, I wanna leave you with the following thoughts. First, I wanna recognize our entire team for their hard work and dedication to safety, operational excellence, and environmental stewardship. APA remains committed to financial and operational discipline. We are focused on leveraging the portfolio to invest in the highest return projects. While activity cadence will impact our first quarter, we are confident in our growth outlook for 2023. In Suriname, the JV has accelerated appraisal at Krabdagu, and we look forward to keeping you informed of our progress. I will turn the call back to the operator. This concludes today's conference call. Thank you for your participation. You may now disconnect. Everyone, have a wonderful day.