Hello and thank you for being here. Welcome to APA Corporation's Third Quarter 2023 Results Conference Call. It is my pleasure to introduce Gary Clark, Vice President of Investor Relations.

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 Christmann. 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 Pursell, Executive Vice President of Development, Tracey Henderson, Senior Vice President of Exploration; and Clay Bretches, 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 the 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 noncontrolling 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 discuss today. A full disclaimer is located with the supplemental information on our website. And 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 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 CrabDagu 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 full 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 Aware. 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 U.S. 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 billion 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 frac 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 investment 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 Cheniere gas supply contract commencing in the second half of the year. 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, in the first quarter of 2023, we expect Permian production will be flat to down as we experienced 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% 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 Riney.

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 U.K. energy profits levy. This was partially offset by a $93 million release of tax valuation allowance due to the use of tax loss carryforwards 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 utilized 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 website. 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 Cheniere 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 1, 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% 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.

Our first question comes from Doug Leggate with Bank of America.

I have a question about Suriname to start with, and then I’ll follow up with a financial inquiry. John, I know you have a couple of wells currently being drilled, but I understand that Hess and Shell, with Shell as the operator, have made a discovery that seems to align with your prospect. Can you share your expectations or the current status? Am I correct in thinking there may be some implications from confirming a working hydrocarbon system? Also, it seems Hess hasn't provided details about whether that was a success, but it appears they are reviewing it right now.

No. Doug, the well we're drilling in the kind of the northwest portion of our block is, 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 trap. But Tracy Henderson is here, and I'll let Tracy provide a little bit more color.

Doug, I think your comments are very accurate. We are seeing a positive trend from the well. We know as much as you do about the information in the public domain, but it seems like we have a favorable outcome regarding the petroleum system. This basically extends the mature proven area further north into Block 42, well beyond the northern boundary of our Block 58, which is promising for the petroleum system. Additionally, it expands the potential area in the Block 58 northern prospects. However, I should emphasize that with these deepwater fans along the entire margin, the main risk factor is the trap. We still need to focus on our trapping geometries, but from a petroleum system perspective, having a functioning trap is positive and enhances our confidence in charging them.

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 Sapakara South at this point as it relates to whether that can help inform an FID in 2023?

Well, a couple of things I have to say, Doug, on Sapakara South. Number one, it's strongly supported from a seismic perspective, and it's an updip test of Sapakara 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 FID and so forth. We've got the appraisal at Sapakara South, which is ongoing. We also got appraisal at Krabdagu, which will follow sometime early next year. So we're excited about that, and we'll just have to get back to you when we're ready.

My follow-up is for Steve. I want to touch on a few points. It seems that Cheniere is not ready to start the contract as early as you would prefer, likely due to LNG prices. What I'm really trying to understand is your comments regarding free cash flow. If I heard correctly, you mentioned that next year, under similar price conditions and excluding Cheniere, cash flow would be higher. Additionally, you've changed the Waha trading contract to reflect a revenue run rate of nearly $300 million. When combining all this information, it seems that free cash flow could increase even with a significantly lower commodity price. Can you clarify if my interpretation is accurate?

Yes, Doug, I believe we need to be patient as we complete the planning process for 2023, and we'll provide all the details in February. As John mentioned, if our capital program turns out to be similar to what we've experienced over the last two quarters, which is approximately $2 billion to $2.1 billion, and we allocate it similarly, we anticipate that in a price environment akin to 2022, our free cash flow for next year will increase. There have been some changes since our last discussion about 2023 in February, particularly with more activity leading to increased capital spending, including an additional rig in the Permian and a couple more rigs in Egypt for 2023. New taxes, especially the energy profits levy in the U.K., have emerged, and there are discussions about possibly raising that rate. However, we believe we will not be subject to the U.S. alternative minimum tax in 2023, which would be favorable if we can defer that until 2024. We’ve also noted that production volume from the North Sea may be a bit more unpredictable. Egypt has started off slower in 2022 than we hoped, which will extend into 2023. We've aimed for transparency regarding our position for 2023 compared to our February discussion. We feel we have solid momentum, are addressing some issues from the second quarter, and the third quarter results are looking better as we head into the fourth quarter. We anticipate a positive start to 2023. So, in summary, let’s wait until February for details on the capital program and allocation, as well as what that will mean for production volume. Overall, we remain optimistic, and the plans we outlined last February still stand, despite a few changes.

And our next question comes from the line of John Freeman with Raymond James.

Just a follow-up on the last line of question. I definitely appreciate the early look on 2023, understanding that there's still some moving parts. But if I just wanted to kind of tap on to what you're saying, Steve, where if you're running kind of in aggregate in the U.S. in Egypt, it looks like on a year-over-year basis, maybe an incremental 4.5 rigs versus what you did this year. Is there a way to sort of parse out of the $2 billion to $2.1 billion CapEx number? How much of that kind of year-over-year increase is kind of activity driven versus cost inflation?

Yes, I would say that John might have some comments on this as well. Looking at the last two quarters, especially the fourth quarter, we are planning to run at what we are targeting for 2023, based on preliminary figures. Most of this has remained consistent with the third quarter. We did experience some downtime in the North Sea with the Ocean Patriot during the third quarter. However, in the last two quarters, we've operated just slightly below or around $500 million per quarter, which translates to an annualized spending rate of about $2 billion. This is a preliminary outlook that might include some inflation, bringing it to possibly $2.1 billion. It is important to note that our planning process is still in its early stages, and this could change. We'll have a clearer idea in February. Overall, I would describe the primary factor behind the changes in capital spending as being related to shifts in activity.

Okay, great. I have a follow-up question regarding Egypt. You did a really good job of catching up and improving the completion cadence significantly in the second half of the year after facing challenges in the second quarter. However, John, you mentioned that some issues in Egypt are not completely resolved. Could you provide more details on what you're referring to? The completion cadence looks promising, but where do you expect to end the year in Egypt?

Yes, we're in good shape, and we've put in a lot of effort to reach this point in a short time. A significant part of our progress has been focused on addressing manpower issues and training. While we're getting closer to our goals, there are still some challenges to navigate, but overall, we're in a solid position.

Our next question comes from the line of Neal Dingmann with Truist.

First question, a little bit on what Freeman was just asking. John, my first question is on production growth. Specifically, you all, I think, characterized '23 as potentially seen, I think, what you deem this 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 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?

I would just mention that Steve provided a detailed update on our early look at the three-year plan, which is quite dynamic. We will revisit this in February. Generally, we are anticipating mid-single digits growth on a BOE basis at the corporate level, driven primarily by oil production in Egypt. Next year, we expect to have a smoother operation in the North Sea, although we will experience some variability. Additionally, we have seen strong performance in the U.S., particularly in the Permian.

Okay. Great detail. 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 billion buyback plan, what remains year-to-date?

I would just say, I'll underscore, we're committed to the returns framework, and we will deliver a minimum of the 60%.

And our next question comes from the line of Bob Brackett with Bernstein.

I had a question on the Cheniere gas supply contract. You mentioned the scale of a $570 million opportunity. Could you break that down for us in terms of volume implied and maybe the price differential between Henry Hub and whether you think about TTF or JKM?

Yes, the contract is valued at $140 million per day and the $570 million figure refers to our pricing assumptions, which are based on an 80% TTF and 20% JKM mix. This was compared to the same period strip for Houston Ship Channel. Additionally, the contract includes various deductions for liquefaction, shipping, shrinkage, and regasification.

Very clear. And that's sort of starting up in September. Is that $140 million a day for 4 months or 5?

It will take five months. The latest that contract can start is August 1, but it could begin earlier. I'm not getting my hopes up.

And our next question comes from the line of Jeanine Wai with Barclays.

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, as you said, the North Sea activity should be consistent with 2022. But 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 sale, but what kind of base decline is the North Sea on.

Yes, Jeanine, this is Dave Pursell. I don't have the exact numbers with me, but consider the two different assets. The 40s, which is a mature waterflood, is experiencing a high single-digit annual decline. These are high water cut, low decline wells. There is pressure maintenance through water injection in many of those assets, but you will see more conventional declines in barrels. So those declines will be higher than the 40s. We can revisit this and determine the blended number, which I recall will be somewhere in the mid- to high teens, but we can refine that further.

Okay. Great. 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. 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?

Yes, I understand our controller might not agree with me referring to it as an asset, but we see it that way in a nonaccounting context. For that reason, we utilized it for the bolt-on acquisition in July in the Delaware Basin. We have employed it for debt tenders and share buybacks as well. Specifically, we take advantage of it during periods when we don't possess any significant nonpublic information, allowing us to execute open market repurchases of shares at a more selective pace. The revolver proves very useful in these situations. Given the current price environment, we are quite comfortable with the revolver's status as it has been for most of the year. Nonetheless, it is important for us to reduce the balance and maintain it over the long term to preserve flexibility for potential bolt-on acquisitions should attractive opportunities arise.

And our next question comes from the line of Charles Meade with Johnson Rice.

John, I'm hoping to get you to elaborate a little bit more your thinking on supercar south to and what kind of piece of the puzzle this might be? I mean my understanding is you could drill appraisal wells in many locations, but the location you do because you're hoping it will answer some questions for you and move you towards sanctioning projects. So can you talk about what the goals were with this location? I think you mentioned it's up dip and how that could play into moving the project forward in '23?

Yes. Regarding Sapakara South, it was an exceptionally high-quality discovery. We encountered 32 meters of pay, with low gas-to-oil ratios around 1,100, and had very high permeability ranging from 1.3 to 1.5 Darcy rock. When we first announced the discovery, we stated a connected volume of over 400 million barrels. Sapakara South represents world-class rock. At that time, we also indicated that we believed there was additional resource that needed further appraisal. This well aims to address that, as we've moved up dip, and we are appraising with solid seismic support. We believe the seismic data is effective and could significantly enhance the Sapakara South discovery.

It would be great to follow up when you have more information to share. For my second question, I believe this might be directed to Steve, but John could answer as well. Neal touched on this earlier. In your press release, you mentioned plans to return at least $1.6 billion in cash through dividends and stock buybacks. The presentation included a useful slide indicating you're at about $1.1 billion right now, with another $130 million coming, meaning you're currently at $1 billion. If I calculate correctly, that leaves approximately $450 million for the last two months, or about $400 million for November and December specifically. Will you need to conduct a tender offer to buy back those shares, or do you think you can manage this through regular market transactions?

Yes, Charles, let me quickly go over the calculations you mentioned. We expect that, based on recent strip prices, our free cash flow for this year will be $2.7 billion, which means we are committed to returning at least $1.6 billion. Year-to-date, we have paid out $127 million in dividends and bought back 26 million shares at $34, totaling $884 million in buybacks. So far this year, that adds up to just over $1 billion. To date, we've repurchased 15% of the company at slightly over $31 per share. With a free cash flow of $2.7 billion, we anticipate total returns of $600 million for the fourth quarter. The dividends will be approximately $80 million, which suggests buybacks of $520 million, of which we've completed about $80 million in October. Your calculations were very close; if we hit around 60%, it would result in about $440 million of additional share buybacks. Historically, we have executed these buybacks through 10b5-1 programs and open market repurchases. We utilize open market repurchases when we don't have material nonpublic information, and we are currently drilling two wells in Suriname. We are aware of the risks involved, and as John mentioned, we are committed to this program. You can expect that we have plans in place to ensure this will be completed by the end of December.

Our next question comes from the line of Paul Cheng with Scotiabank.

I have two questions. First, regarding the mid-single-digit oil production growth for next year, is this based on the fourth quarter or the full year 2022 level? If it’s based on the full year 2022 level, it might indicate that your oil production next year could be lower than the fourth quarter level. With the increased activities, is there a reason why the average production for oil growth next year would be less than the fourth quarter level? My second question is straightforward. In the Permian, you're planning to operate 5 rigs. Does that include any activity in the Alpine High? Also, what is your perspective on the current commodity prices in relation to the gas wells versus oil-only wells?

So, for 2023, we are still making progress. We will provide more detail in February, but generally, we expect year-over-year growth in BOEs to be in the mid-single digits, primarily driven by oil. This aligns with the three-year plan we shared last February. Currently, we have five rigs operating in the Permian, with two in the Midland Basin and three in the Delaware. We will have activity at Alpine High, and we're pleased with the mix as we believe those wells are competitive given the current gas and oil prices.

John, should we assume you're going to have at least 1 rig at Alpine High or is that just not necessarily it may be...

I would say today, just assume there's likely 3 in the Delaware and Alpine High will be part of that program.

And our next question comes from the line of Leo Mariani with MKM Partners.

I was hoping to jump back to the North Sea here real quick. Just kind of looking at the production over the last couple of years, certainly, you guys have been hit with a lot of downtime there. You're forecasting higher production here 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.

I would say that a lot of our situation is due to coming out of our maintenance turnaround season. We had to catch up in 2022 for the issues from 2020 and 2021, as the Covid years really impacted us, limiting what we could do on the tars. Additionally, our infrastructure is aging, and when problems arise, it takes longer to resolve them. However, I believe we have moved past many of these challenges. Moving forward, we will provide guidance with wider ranges, but currently, we have good momentum and operations are running relatively smoothly.

Okay. And just jumping over to Egypt here. Just looking at your kind of gross oil volumes, look like those were down a little bit here in 3Q versus 2Q. Can you just give us some indications as we get into kind of 4Q and early next year? Do you think 3Q is the low point on those gross oil volumes, and we start to have some nice growth into kind of the end of the year? And then do you see kind of 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?

Yes. I think some of that is just timing of the well connections we had this quarter, and we've got good momentum really across the whole portfolio going into the fourth quarter. We're off to a good start and we had some wells that have come on and things. So we do think Egypt is going to be one of the big drivers in '23 and beyond.

Our next question comes from the line of David Deckelbaum with Cowen.

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 ex downtime heading into next year?

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. So I don't anticipate anything significantly outsized from normal and we should be in a period today with most of that behind us where things are going to run a little smoother.

Appreciate that. And maybe if I could just ask for a little bit more color on the Cheniere contract. I think you all had marked today based on strip 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?

Yes. Unfortunately, it’s challenging to provide a general approach to understanding this because some costs, like shrinkage and fuel, impact volume loss. These costs are linked to the TTF and JKM prices, while others are fixed contractual amounts that have some inflation adjustments over time. A notable example is the liquefaction fee. Therefore, it's not straightforward to establish a generic rule for how this interacts with different LNG prices or the Houston Ship Channel. This is why we present it as a margin over the Houston Ship Channel. As I mentioned earlier, we sell all the products we produce in the Permian basin and enter into pipeline contracts primarily to keep less liquid markers, like Waha Hub, more aligned with larger, more liquid markets. Our marketing organization manages these contractual commitments. For this reason, we view the Cheniere contract as a margin over purchased product because we buy product on the Gulf Coast and deliver it to Cheniere. The pricing we receive is based on a netback calculation, and they take title to the product at their facility. We do not hold any title to the product as it moves through their plant or the liquefied product that comes out, and we do not handle shipping.

Our next question is a follow-up from Doug Leggate with Bank of America.

I'm sorry for interjecting again. John, I've been paying attention to all the inquiries about the North Sea, including concerns about the increased windfall tax risk, less predictability, and the lifespan of the field. The obvious question for me is whether this is a core asset for APA. At what point, if another key area like Suriname arises, does the North Sea become non-essential? Essentially, is it up for sale?

Yes. I would say that the North Sea is a core asset for us right now. There are factors affecting our ability to invest in the future, and we have to continually consider that. We benefit from Brent pricing, high netbacks, and strong free cash flow. However, we also have a dynamic portfolio, and we are always looking to enhance our investment in other assets. As circumstances change, sometimes beyond our control, it can limit those options. So while it is a core asset now, we are always evaluating it as we plan for the future.

I'm showing no further questions. So with that, I'll hand the call back over to President and CEO, John Christmann, for any closing remarks.

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. In Suriname, we're drilling an appraisal well at Sapakara South and an exploration well at Aware. 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.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating, and you may now disconnect.