APA Corporation

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 will be a question and answer session. To ask a question during the session, you'll need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your 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 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, Executive Vice President of Exploration, and Clay Bratches, 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 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.

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. And 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 million barrels 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 Krabdago. And 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, and 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 to $2.1 billion, which is consistent with what we indicated back in early November. 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% to 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. However, 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 UK 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 Crab Dago and subsequent flow testings. 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 Chenier. Steve 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, and 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 Chenier 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. And in CERNOM, 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. And with that, I will turn the call over to Steve 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 pretax unrealized gain on derivatives and a $47 million release of evaluation 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. However, 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 Chenier gas sales contract at current strip prices would offset the impact of higher taxes in the UK 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 Chenier 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 Chenier. Clearly, 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 UK recently increased its energy profits levy from 25 percent to 35 percent and extended the effective period through March of 2028. As a result, the combined statutory tax rate in the UK 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 UK current tax expense of $550 to $575 million this year. In the US, 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. And 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 1-1 on your telephone. To withdraw your question, please press star 1-1 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. Steve Reine will not be available for Q&A, as he unfortunately needs to attend to a family matter. So Ben Rogers, 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. So we'll give it back to you, Operator, for the Q&A.

Thank you. One moment for our first question. And 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 a really, really solid quarter in 4Q. Nice to see the rig efficiency gain. 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 22. And 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 that higher success rate is sustainable going forward.

Yeah, John, I'd say the program has 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. So you're running a little higher on the success rate. as we get some of that low-hanging fruit initially.

Great. And then a follow-up on looking at Suriname. Has the expiration well been identified where that will be after the two appraisal wells? And is the entirety of the 23 plan, the two appraisals and the one expiration, 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 CERN, please.

Yeah, I would just say today we've got the two appraisal wells that we're drilling at Crab Dago, and that's going to take a good portion of the first part of the year. That's where the priority is now. And then we do have one exploration slot that is still being worked, and we're still debating that. partner on you know which well that will be but there are multiple wells identified it's just a matter of which one so for now that is the plan and you know obviously we'll we'll readdress that throughout the year all right thanks John thank you one moment for our next question and the next question comes from Janine why with Barclays your line is now open

Hi, good morning, everyone. Thanks for taking our questions.

You bet, Janine.

Good morning, John. Our first question may be just keeping along with John's on CERN. The estimate for resource at Sapakara is now over 600 million barrels of oil in place. So 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? And we know you're doing a ton of appraisal at Krabdago this year as well.

Yeah, I mean, in terms of the estimate at Sapacara, 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 going to have a high recovery, and, you know, it'll be a big key component, you know, potentially of a future project. So we have great confidence there. And then we've got, you know, the two appraisal wells that are being drilled at Crab Daggy right now. In terms of, you know, development size and so forth, as we've said, we're working towards, you know, first project. And, you know, really right now it's premature to talk about anything, you know, pending the results of appraisal at Crab Dagu, which we're very excited about. And, you know, it's moving right along.

Okay. Well, stay tuned for those appraisal results. Amy, moving to the U.S., you mentioned in your prepared remarks that you're managing the portfolio for cash flow and not production. And so 23 is driven by oil this year. And so you also curtailed some Alpine High production in January. Can you provide any further color on what the price sensitivity is of natural gas curtailments at Alpine High? Thank you.

Yeah, this is Dave Purcell. It's a good question. You know, our curtailments earlier in the year were relatively small, but when Waha, you know, Waha has 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. So it depends on dry gas versus wet gas. There's a lot that goes into it, but... As we look at it now, we've been flowing Alpine full out through most of January and February. So not going to give you a specific price marker, but we're looking at it pretty extensively every day and every week with the marketing team.

Thank you. One moment for our next question. And our next question comes from Charles Mead with Johnson Rice. Your line is now open.

Good morning, John, to you and the whole Apache team there. I want to ask a question about the Crabdegoo appraisals. And I recognize that we still have to get the important data that those appraisals are designed to get with not just what you see on the logs but with the flow test. But from... From my seat, and I think for most of the people outside looking in, you guys have two, I guess you're about to have two appraisals ongoing. It really looks like you guys are trying to drive 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 Crab Dago, right? And you saw us move from Sopocara with two appraisal wells there, and we're very pleased with those results. And, you know, Sopocara, too, kind of came in as we had projected and modeled. And, you know, obviously anxious for the results at Crab Dago. And so, 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 trying to get to. And the second one, just a quick follow-up for me. How would you set our expectations on when we're going to hear about the crab-baguio flow test? 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, and, you know, the second one has been on location, sputting any time now. So there will be a lag, and we'll just have to see what we decide to do and work with Total in terms of what we come back with in timing. But, 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 Chen with Scotiabank. Your line is now open.

Thank you. Good morning, guys. Good morning, Paul. Two more questions.

John, can you remind us that what is Alpine High's role in your longer-term portfolio?

I think at one point several years ago, you sort of weighed down everything, and then GasPi became a little bit better, and I think you guys go back and sort of It seems like it's having a role in the long term, but how should we look at the Alpine High? And also the same question is that I think you guys have not done any photon acquisition in the last 12, 18 months. Some of your peers have done so. How should we look at photon acquisition for you guys over the next two or three years? Is that a... could 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 in Egypt? Thank you.

So, two really good questions, Paul. I mean, the first thing I would say is Alpine High is a nice piece of our Permian portfolio, and we look at it as part of the Delaware Basin. And 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 going to be bringing on, you know, during the first quarter. And then you'll see a, you know, kind of a break. And then we've got, you know, five wells that will be coming on year end. But it is something we can toggle. And, you know, we'll tend to leverage that. And what you've seen is this year is 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 when you look at 2024 and beyond as some of the basin bottlenecks open up. So 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 game plan. I think when you step back in your second question related to bolt-on acquisitions, we did do our first acquisition last year in the Delaware, a very nice tuck-in acquisition. It was one that we're constantly in the market looking at things, as is we have assets in the market. We typically wait to talk about things until there's a transaction or something to do. The tuck-in we did last year is something that's been exceeding our acquisition forecast, something we're very happy with, and it's now integrated into our Delaware package and our Delaware assets. So I think it's something you've just got to monitor. I mean, if you've got a handle on your current inventory, you've got a handle on costs, and if there are things that we think we can add at attractive costs where we can drive incremental returns, then we're not opposed to doing that. But it's been a high bar, and that's why we've really only done one transaction over the last couple of years. And we're going to continue to drive a balanced portfolio. We are emphasizing expiration with the program we've got in CERNOM. But, 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. And our next question comes from Doug Legate 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. I'm going to try it again. Suriname recovery factors, given your prosody permeability is world-class rock, obviously. Can you give us some idea what you think that looks like? And if I may reference the more than 800 million as opposed to the 600 million recovery It looks like we're heading to a joint potential Sapakara-Kirbdagu development. What should we think in terms of timing and scale of an FID?

um great question doug and uh you know there's a there's a lot of work we've done and we have a lot of confidence in what we've put out uh but there's also a lot of work you know left to do so i will talk about you know give you a little bit of color on sapacara and then i'm going to you know bring dave in if he wants to add anything You've really got two areas. You are correct, we are working towards with our partner, potentially a development hub, where you'd be bringing in both Crabdago and Saipacara. They are a little different in terms of the makeup and so forth. You know, Sopocara is predominantly one package. Really, really high-quality rock. When you're talking low-GOR oil, you know, 1,100-GOR oil, and you're talking 1.3 to 1.5 Darcy rock, one nice blocky sand, you're going to have high recoveries. And that's really all I'll say at this point. You'd want to get into feed study and do more work before we come out with with more specifics there. So some of the questions you're asking are things that will come later. And then Crab Dago 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. And so the work we're doing to, you know, understand those and quantify those is really important to, you know, determining potential scale and scope. So, you know, all things underway, we prioritize it, which is why you've got two rigs there. And, you know, we're anxiously awaiting those as well because it's going to, you know, have an impact on scope and scale.

uh thank you for that john i guess we're not going to get the the fid timing question but i told you i would try again um you know i'm torn as to whether i asked my second on suriname as well i think i think i'm going to so let me try this um did you find an oil water contact on the second appraisal well at sapacara and i guess what i'm really trying to think of there's you know the The focus obviously is on these two, but there's still, if I recollect, 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. To generally characterize it for us, is this going to be one and done, or do you see capacity for a longer-term exploration development program in the basins?

Well, a bunch of questions in there, so I'll try to answer all of them to the extent I can. You know, one, Sapa Car South 2 was an up-dip appraisal. So, you know, I think that was important in terms of confirming, you know, what we confirmed there. If you go over to Crab Dago, I'll remind you Baja in Block 53 was a discovery of a down dip lobe in that Crab Dago fairway. So there are multiple levels, and that's part of what you're driving at. There's also a pretty good chance we're appraising up dip at Crab Dago 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 Sapacara and Crab Dago that could also go into a potential hub. And then 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. uh the the tricks been you know trap and seal as you get out there so you know i do believe we will have an ongoing program uh in surname as there is a lot of prospectivity thank you one moment for our next question and the next question comes from the line of neil dingman with truist your line is open morning john thanks for the time um john my

the first question really just a broader one on shallow return or specifically maybe capital case. The last couple of quarters, y'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, you have kind of a minimum level that you think about going forward for the, 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. And I'll underscore, when we say on the buybacks, we'll do a minimum of 60%, as you, you know, you saw last year, we were able to execute on that. You know, we feel strongly about it today as well. And, you know, that's what you'll see us do. By nature, things are back in 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. And, you know, you'll see 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 sheets. So, you know, yes, I'll underscore that.

No, great point. Okay. And then just a second question on domestic activities. It's been asked a little bit, but I'm just wondering, You know, you all mentioned having the two southern Midland Basin, the three Delaware rigs. How fluid is this? Could this change depend on prices or even more activity in that newer Titus area? Just one 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 planting pads way down the road, and it gives us time to really execute and think about how to maximize the NPV. you know, the returns. And so that two-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 where 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. And 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. And our next question comes from the line of Roger Reed with Wells Fargo. Your line is open.

Yeah, good morning. Good morning, Roger. Good morning. Happy to finally show up here. One quick question for you on your comments about the outlook for the agreement with Chenier, the range of 500 to 1.25. When we look at it between 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 slump here.

uh and big moves uh we expect continued volatility over in europe is you know which which is the the waiting towards it's it's going to be more on the you know the the global ellen you know ttf or jkm uh but i'll i'll let ben uh 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 ship channel this year, mainly from Freeport LNG being offline and just generally milder weather. So a lot of domestic variables that are impacting the Houston ship channel. But to John's point, with the war in Ukraine and a milder winter over in Europe, I think it was 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. And we have that inherently on the oil side by selling our North Sea and Egyptian oil barrels at Brent-based pricing. And 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. But 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 I guess could cause you to come in underneath or any of the other issues that you mentioned, kind of like, you know, well cadence, stuff like that?

I mean, it's exactly those things, Roger. But, I mean, we've got good confidence in the program. And, you know, it's underpinned by, you know, two onshore areas with Egypt and Permian. But it will be that very thing. It's the turning lines and the timing. And you're seeing that a little bit with the first quarter because we only had four wells in the U.S. fourth quarter last year, and they were late, one Permian, three chalk. So a lot of that's going to be driven by the function of just what's the timing on the execution. And when you're running... you know, five rigs in the U.S., it's going to be lumpy. And in Egypt, it took us a little bit of time to kind of get our legs under us with the 17-rig program. But, I mean, those are the key things to watch. But we have good confidence in our projections.

Thank you. And 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. So maybe you could talk about what you're seeing real time, both international and in the U.S. in terms of inflation. Have you seen any green shoots that this period of immense inflation is starting to move back into your direction? Sure.

Yeah, Neil, a good question. I would say we spend a lot of time trying to stay about a year ahead of our programs and so with our contracts and things because that gives us, you know, the visibility in terms of the spend. And so today, a lot of what you're seeing is, you know, contracts based on, you know, the back half of last year's pricing. So 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 going to see cost structures, you know, follow. They just tend to lag, but they will follow the decks. It just takes a little bit of time to play catch up. So, 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 you could 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. And any comments you have around the tax rate broadly would be helpful.

Yeah, I would just say that it's made the North Sea less competitive relative within our portfolio. And so... you know, as we look at that, still an asset that, you know, we're going to manage for cash flow and, you know, we'll get good performance there and we're going to 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. But, you know, longer term, you know, 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 and so 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 calvin your line is now open

Hey John, thanks for the time today. You bet.

I 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 and then what we should expect once we're 10% higher in the fourth quarter of 23 going into 24 and beyond there?

No, I think you'll see a pretty robust program in Egypt. The thing you have to recognize here, we've got two factors going on. You have a big discovery that was predominantly gas and cost that's starting to decline. And that's why you're seeing the oil growth, which is where the drilling program with the 17 rigs are focused in Egypt. So you'll see that oil mix is what's growing in Egypt as well, and that's what's underpinning that program. uh... you know it's a it's an onshore uh... you know multi rig program and 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 uh... we're at shale and you can do pad math but you know the nice thing is is this is conventional rock that flows at you pretty hard and fast and sets up you know uh... smaller developments but very impactful material developments and so uh... 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. And my second one is just on Suriname. It sounds like we're obviously waiting for the appraisal results from Crab to Goo and the intention to potentially build out a hub there. I guess, does that necessarily preclude, you know, Would you view this as you kind of need to combine both Sapakara and Crabdegoo into one hub system to maximize economics and that Sapakara wouldn't necessarily support a development on its own?

I'll just say both us and our partner are motivated to get the scope and scale right. correct from the get-go. And, you know, the larger the project, the larger the boat, the better the economics are going to be. And so, you know, there's no reason to try to get into, 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 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 going to be steadily high for quite a few years. You know, should we expect the result of that rig being dropped? Is it going to kind of accelerate some of the production decline? 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 abandonment timeframes as we model that out today. And really, you look at this year, not much impact from the Ocean Patriot. It was drilling some things that are bigger impact, subsea wells that take time to come into play. So it does have an impact. You know, start to see a little bit in 24, 25 and beyond. But it doesn't really drive. I mean, we're still, you know, looking at early 2030s for both 40s and barrel. And, you know, when we bought the 40s 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. And so here we are, you know, more than a decade longer, 12, you know, 10 years, 11 years longer, and, you know, still looking at, you know, close to another decade. So there's still good productivity and life there. We're just going to manage it, you know, for cash flow and be very prudent about, you know, the future investments.

Well, that's helpful. And then just jumping over to the U.S., just wanted to get a sense,

Is there anything at all planned in the Austin shock in 2023? I know you guys had some wells that kind of came on, you know, late last year. So if there's any update you have in that asset. And then also just to follow up on Alpine High a little bit, 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 hopefully that gas market will improve. But do you guys have long-term designs on using Alpine High as a feedstock for some of these Gulf Coast LNG facilities?

The thing I would say is recognize the contract with Chenier is a separate deal. It's a corporate-level deal. We buy gas and ship channels. It's separate and aside from our equity gas that we produce. We sell that in basin at Waha, and prices at Waha are going to dictate what we do in basin. 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 where we've got some non-op interest there that others are drilling, but nothing planned in our budget this year for chalk drilling.

Thank you. One moment for our next question. And our next question comes from Arun Jaywaran 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 Krav Dagu. What are you and the partners' plans in terms of incremental exploration post-COVID? the evaluation results of Crab Dagger 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. Both teams are spending time high grading. If you go back and look at both Awari and Bonboni and Block 58, we have working petroleum systems, hydrocarbon systems out there. The main targets in both cases failed because of breach of seal. And so, 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 where we've had great success. So 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. And just maybe one follow-up in the Permian situation. 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 one or so well at the sales. What drove that in 2022? Were you building some ducks? And, you know, just thoughts on, you know, will that shift a little bit as we think about 2023 because you have a pretty robust program? production growth outlook?

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, and so a lot of it's just the timing of the pads, completing the pads, and then working through the completion, you know, timing. So, With only two rigs, you know, you're going to see lumpiness from us, whereas if we were running a lot more rigs and that lumpiness kind of starts to, you know, work itself out and normalize. So 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 Jeffery with Tudor Pickering. Your line is open.

Hey, good morning, everyone. Appreciate y'all taking my questions.

You bet, Jeff.

Yeah, thanks for speaking to me. And 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. So as you think about the 2023 guide, I was hoping you could speak to 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 and 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 tracking execution from here on the 2020 program.

Well, I mean, Jeff, a question. We obviously try to guide to what we believe are 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. But, you know, I think we've given very realistic and good guides, you know, for 2023. And I think there's good confidence from the team. I know I sure asked that question, and it's the response I get and the response that I'm, you know, comfortable to relay.

Okay, great. And then I guess just on operations and efficiencies, again, you know, obviously improved quite a bit as you move through 2022. Just want to get a sense for what you're focusing on from that perspective and, you know, what kind of running you might see for improvements from here.

It's all about operational excellence and continuing to try to improve and learn from things as you go. In Egypt, we're drilling in some new areas with seismic and some of the exploration that we're doing there. And so within those areas, we should see improvement as we drill more wells and areas you've drilled before. Yeah. You know, you're seeing some of that. And, you know, the big thing is, 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. And you saw great progress on the safety front. We're going to 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 Christman for closing remarks.

Yes, thank you. And before closing today's call, I want to leave you with the following thoughts. First, I want to 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. Lastly, in Suriname, the JV has accelerated appraisal at Krav Dagu, 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. Thank you. Thank you. music music

Thank you. Thank you.

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 will be a question and answer session. To ask a question during the session, you'll need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your 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 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, Executive Vice President of Exploration, and Clay Breches, 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 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.

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. And 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 million barrels 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 Krabdago. And 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, and 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 to $2.1 billion, which is consistent with what we indicated back in early November. 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% to 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. However, 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 UK 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 Crab Dago and subsequent flow testings. 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 Chenier. Steve 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, and 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 Chenier 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. And in CERNOM, 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. And with that, I will turn the call over to Steve Reine.

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 pretax unrealized gain on derivatives and a $47 million release of evaluation 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. However, 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 Chenier gas sales contract at current strip prices would offset the impact of higher taxes in the UK 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 Chenier 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 Chenier. Clearly, 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 UK recently increased its energy profits levy from 25% to 35% and extended the effective period through March of 2028. As a result, the combined statutory tax rate in the UK 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 UK current tax expense of $550 to $575 million this year. In the US, 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. And 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 1-1 on your telephone. To withdraw your question, please press star 1-1 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. Steve Reine will not be available for Q&A, as he unfortunately needs to attend to a family matter. So Ben Rogers, 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. So we'll give it back to you, Operator, for the Q&A.

Thank you. One moment for our first question. And 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 a really, really solid quarter in 4Q. Nice to see the rig efficiency gain. 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 22. And 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 that higher success rate is sustainable going forward.

Yeah, John, I'd say the program has 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. So you're running a little higher on the success rate. as we get some of that low-hanging fruit initially.

Great. And then a follow-up on looking at Suriname. Has the expiration well been identified where that will be after the two appraisal wells? And is the entirety of the 23 plan, the two appraisals and the one expiration, 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 CERN, please.

Yeah, I would just say today we've got the two appraisal wells that we're drilling at Crab Dago, and that's going to take a good portion of the first part of the year. That's where the priority is now. And then we do have one exploration slot that is still being worked, and we're still debating that. partner on you know which well that will be but there are multiple wells identified it's just a matter of which one so for now that is the plan and you know obviously we'll we'll readdress that throughout the year all right thanks John thank you one moment for our next question and the next question comes from Janine why with Barclays your line is now open

Hi, good morning, everyone. Thanks for taking our questions.

You bet, Janine.

Good morning, John. Our first question, maybe just keeping along with John's on CERN, the estimate for resource at Sapakara is now over 600 million barrels of oil in place. So 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? And we know you're doing a ton of appraisal at Krabdago this year as well.

Yeah, I mean, in terms of the estimate at Sapacara, 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 going to have a high recovery, and, you know, it'll be a big key component, you know, potentially of a future project. So we have great confidence there. And then we've got, you know, the two appraisal wells that are being drilled at Crab Daggy right now. In terms of, you know, development size and so forth, as we've said, we're working towards, you know, first project. And, you know, really right now it's premature to talk about anything, you know, pending the results of appraisal at Crab Dagu, which we're very excited about. And, you know, it's moving right along.

Okay. Well, 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. And so 23 is driven by oil this year. And so you also curtailed some Alpine High production in January. Can you provide any further color on what the price sensitivity is of natural gas curtailments at Alpine High? Thank you.

Yeah, this is Dave Purcell. It's a good question. You know, our curtailments earlier in the year were relatively small, but when Waha, you know, Waha has 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. So it depends on dry gas versus wet gas. There's a lot that goes into it, but... As we look at it now, we've been flowing Alpine full out through most of January and February. So not going to give you a specific price marker, but we're looking at it pretty extensively every day and every week with the marketing team.

Thank you. One moment for our next question. And our next question comes from Charles Mead with Johnson Rice. Your line is now open.

Good morning, John. To you and the whole Apache team there. I want to ask a question about the Crabdegoo appraisals. And I recognize that we still have to get the important data that those appraisals are designed to get with not just what you see on the logs but with the flow test. But from... From my seat, and I think for most of the people outside looking in, you guys have two, I guess you're about to have two appraisals ongoing. It really looks like you guys are trying to drive 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 Crab Dago, right? And you saw us move from Sopocara with two appraisal wells there, and we're very pleased with those results. And, you know, Sopocara, too, kind of came in as we had projected and modeled. And, you know, obviously anxious for the results at Crab Dago. And so, 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 trying to get to. And the second one, just a quick follow-up for me. How would you set our expectations on when we're going to hear about the crab-baguio flow test? 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, and, you know, the second one has been on location, sputting any time now, so there will be a lag, and we'll just have to see what we decide to do and work with Total in terms of what we come back with in timing. But, 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 Chen with Scotiabank. Your line is now open.

Thank you. Good morning, guys. Good morning, Paul. Some more questions.

John, can you remind us that what is Alpine High's role in your longer-term portfolio?

I think at one point several years ago, you sort of weighed down everything, and then GasPi became a little bit better, and I think you guys go back and sort of seems like it's having a role in the long term, but how should we look at the Alpine High? And also the second question is that I think you guys have not done any photon acquisition in the last 12, 18 months. Some of your peers have done so. How should we look at photon acquisition for you guys over the next two or three years? Is that a could play a reasonable role or that you will be focusing more of your effort in exploration, like in surname and also that the activity level in Egypt? Thank you.

So, two really good questions, Paul. I mean, the first thing I would say is Alpine High is a nice piece of our Permian portfolio, and we look at it as part of the Delaware Basin. And 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 going to be bringing on, you know, during the first quarter. And then you'll see a, you know, kind of a break. And then we've got, you know, five wells that will be coming on year end. But it is something we can toggle. And, you know, we'll tend to leverage that. And what you've seen is this year is 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 when you look at 2024 and beyond as some of the basin bottlenecks open up. So 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 game plan. I think when you step back in your second question related to bolt-on acquisitions, we did do our first acquisition last year in the Delaware, a very nice tuck-in acquisition. It was one that we're constantly in the market looking at things, as is 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 acquisition forecast, something we're very happy with, and it's now integrated into our Delaware package and our Delaware assets. So I think it's something you've just got to monitor. I mean, if you've got a handle on your current inventory, you've got a handle on costs, and if there are things that we think we can add at attractive costs where we can drive incremental returns, then we're not opposed to doing that. But it's been a high bar, and that's why we've really only done one transaction over the last couple of years. And we're going to continue to drive a balanced portfolio. We are emphasizing expiration with the program we've got in Suriname. But, 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. And our next question comes from Doug Legate 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. I'm going to try it again. Suriname recovery factors, given your prosody permeability is world-class rock, obviously. Can you give us some idea what you think that looks like? And 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 Safiqara-Kirbaidu development. What should we think in terms of timing and scale of an FID?

um great question doug and uh you know there's a there's a lot of work we've done and we have a lot of confidence in what we've put out uh but there's also a lot of work you know left to do so i will talk about you know give you a little bit of color on sapacara and then i'm going to you know bring dave in if he wants to add anything You've really got two areas. You are correct. We are working towards, with our partner potentially, a development hub where you'd be bringing in both Crab Dago and Saipakara. um they are a little different in terms of the the makeup and so forth you know sapacara is predominantly one package uh really really high quality rock when you when you're talking low gr oil uh you know 1100 gr oil and you're talking one three to one five darcy rock uh one nice blocky sand you're going to have high recoveries and uh and that's really all i'll say at this point you'd want to get into feed study and do you know more work before we come out with with more specifics there. So some of the questions you're asking are things that will come later. And then Crab Dagu, there's three targets there. It is the incremental 200 that you've referenced there, and we're in the process of appraising that. You've got a range of GORs there, depending on the zones. And so the work we're doing to, you know, understand those and quantify those is really important to, you know, determining potential scale and scope. So, you know, all things underway, we prioritize it, which is why you've got two rigs there. And, you know, we're anxiously awaiting those as well because it's going to, you know, have an impact on scope and scale.

uh thank you for that john i guess we're not going to get the the fid timing question but i told you i would try again um you know i'm torn as to whether i asked my second on suriname as well i think i think i'm going to so let me try this um did you find an oil water contact on the second appraisal well at sapacara and i guess what i'm really trying to think of there's you know the The focus obviously is on these two, but there's still, if I recollect, 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. To generally characterize it for us, is this going to be one and done or do you see capacity for a longer term exploration development program in the basin?

Well, a bunch of questions in there, so I'll try to answer all of them to the extent I can. You know, one, Sapa Car, South 2 was an up-dip appraisal. So, you know, I think that was important in terms of confirming, you know, what we confirmed there. If you go over to Crab Dago, I'll remind you Baja in Block 53 was a discovery of a down dip lobe in that Crab Dago fairway. So there are multiple levels, and that's part of what you're driving at. There's also a pretty good chance we're appraising up dip at Crab Dago 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 Sapacara and Crab Dago that could also go into a potential hub. And then 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 there. uh the the tricks been you know trap and seal as you get out there so you know i do believe we will have an ongoing program uh in suriname as there is a lot of prospectivity thank you one moment for our next question and the next question comes from the line of neil dingman with truist your line is open morning john thanks for the time um john my

the first question really just a broader one on shallow return or specifically maybe capital case. The last couple of quarters, y'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, you have kind of a minimum level that you think about going forward for the, this year, this quarter. I mean, I'm just wondering from a, shareholder or buyback perspective, if you're able to frame anything up.

I think we have a good question. We have great confidence in the framework we put forward. And I'll underscore, when we say on the buybacks, we'll do a minimum of 60%, as you saw last year, we were able to execute on that. We feel strongly about it today as well. And that's what you'll see us do. By nature, things are back in 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. And, you know, you'll see 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 sheets. So, you know, yes, I'll underscore that.

No, great point. Okay. And then just a second question on domestic activities. It's been asked a little bit, but I'm just wondering, 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 one for plans remainder, maybe more second half of the year.

I would just say we're in a really good cadence in the Southern Midland Basin. You're seeing it in our results because we're planting pads 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. And so that two-rig program has 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. And then we've integrated Titus in. So it's really just part of our Delaware program. And, you know, it's ours.

Thank you. One moment for our next question. And our next question comes from the line of Roger Reed with Wells Fargo. Your line is open.

Yeah, good morning. Good morning, Roger. Good morning. Happy to finally show up here. One quick question for you on your comments about the outlook for the agreement with Chenier, the range of 500 to 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 slump here and big moves. We expect continued volatility over in Europe. Which is the weighting towards?

It's going to be more on the global L and TTF or JKM, but I'll let Ben provide any additional details.

That's right. I mean, there's a lot of variables that go into it. We've seen weakness in the ship channel this year, mainly from Freeport LNG being offline and just generally milder weather. So a lot of domestic variables that are impacting the Houston ship channel. But to John's point, with the war in Ukraine and a milder winter over in Europe, I think it was 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. And, you know, we have that inherently on the oil side by selling our North Sea and Egyptian oil barrels at Brent-based pricing. And 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. But 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, the risk factors on that, you know, things that, uh, which I guess could cause, cause you to come in underneath, uh, or any of the other issues that you mentioned, kind of like, you know, well cadence, stuff like that.

I mean, it's, it's exactly those things, Roger, but I mean, we've got good confidence in the program and, uh, you know, it's underpinned, uh, you know, two onshore areas with Egypt and Permian and, um, But it will be that very thing. It's the turning lines and the timing. And you're seeing that a little bit with the first quarter because we only had four wells in the U.S. fourth quarter last year, and they were late, one Permian, three chalk. So a lot of that's going to be driven by the function of just what's the timing on the execution. And when you're running... you know, five rigs in the U.S., it's going to be lumpy. And in Egypt, it took us a little bit of time to kind of get our legs under us with the 17-rig program. But, I mean, those are the key things to watch. But we have good confidence in our projections.

Thank you. And 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. So maybe you could talk about what you're seeing real time, both international and in the U.S. in terms of inflation. Have you seen any green shoots that this period of immense inflation is starting to move back into your direction?

Yeah, Neil, a good question. I would say we spend a lot of time trying to stay about a year ahead of our programs and so with our contracts and things because that gives us, you know, the visibility in terms of the spend. And so today, a lot of what you're seeing is, you know, contracts based on, you know, the back half of last year's pricing. So 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 going to see cost structures, you know, follow. They just tend to lag, but they will follow the decks. It just takes a little bit of time to play catch up. So, 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 you could 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. And any comments you have around the tax rate broadly would be helpful.

Yeah, I would just say that it's made the North Sea less competitive relative within our portfolio. And so... you know, as we look at that, still an asset that, you know, we're going to manage for cash flow and, you know, we'll get good performance there and we're going to 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. But, you know, longer term, you know, 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 and so 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 calvin your line is now open

Hey, John, thanks for the time today. You bet.

I 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 growth production curve and then what we should expect once we're 10% higher in the fourth quarter of 23 going into 24 and beyond there?

No, I think you'll see a pretty robust program in Egypt. The thing you have to recognize here, we've got two factors going on. You have a big discovery that was predominantly gas and cost that's starting to decline. And that's why you're seeing the oil growth, which is where the drilling program with the 17 rigs are focused in Egypt. So you'll see that oil mix is what's growing in Egypt as well, and that's what's underpinning that program. uh... you know it's a it's an onshore uh... you know multi rig program and 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 uh... we're at shale and you can do pad math but you know the nice thing is is this is conventional rock that flows at you pretty hard and fast and sets up you know uh... smaller developments but very impactful material developments and so uh... 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.

And my second one is just on Suriname. Now, it sounds like we're obviously waiting for the appraisal results from Crab to Goo and the intention to potentially build out a hub there. I guess, does that necessarily preclude, you know, Would you view this as you kind of need to combine both Sapakara and Crabdegoo into one hub system to maximize economics and that Sapakara wouldn't necessarily support a development on its own?

I'll just say both us and our partner are motivated to get the scope and scale right. correct from the get-go. And, you know, the larger the project, the larger the boat, the better the economics are going to be. And so, you know, there's no reason to try to get into, 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 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 going to be steadily high for quite a few years. You know, should we expect the result of that rig being dropped? Is it going to kind of accelerate some of the production decline? 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 abandonment timeframes as we model that out today. And really, you look at this year, not much impact from the Ocean Patriot. It was drilling some things that are bigger impact, subsea wells that take time to come into play. So it does have an impact. You know, start to see a little bit in 24, 25 and beyond. But it doesn't really drive. I mean, we're still, you know, looking at early 2030s for both 40s and barrel. And, you know, when we bought the 40s 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. And so here we are, you know, more than a decade longer, 12, you know, 10 years, 11 years longer, and, you know, still looking at, you know, close to another decade. So there's still good productivity and life there. We're just going to manage it, you know, for cash flow and be very prudent about, you know, the future investments.

Well, that's helpful. And then just jumping over to the U.S., just wanted to get a sense,

Is there anything at all planned in the Austin shock in 2023? I know you guys had some wells that kind of came on, you know, late last year. So if there's any update you have in that asset. And then also just to follow up on Alpine High a little bit, 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 hopefully that gas market will improve. But do you guys have long-term designs on using Alpine High as a feedstock for some of these Gulf Coast LNG facilities?

The thing I would say is recognize the contract with Chenier is a separate deal. It's a corporate-level deal. We buy gas and ship channels. It's separate and aside from our equity gas that we produce. We sell that in basin at Waha, and prices at Waha are going to dictate what we do in basin. 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 where we've got some non-op interest there that others are drilling, but nothing planned in our budget this year for chalk drilling.

Thank you. One moment for our next question. And our next question comes from Arun Jaywaran 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 Krav Dagu. What are you and the partners' plans in terms of incremental exploration post-COVID? the evaluation results of Crab Dagger 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. Both teams are spending time high grading. If you go back and look at both Awari and Bonboni and Block 58, we have working petroleum systems, hydrocarbon systems out there. The main targets in both cases failed because of breach of seal. And so, 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 where we've had great success. So 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. And just maybe one follow-up in the Permian situation. John, as I think about your 2022 program in the broader Permian, including in 4Q, the company didn't place as many wells on the sales as we would have thought in terms of our modeling. Looking at 4Q, I think you placed one or so well at the sales. What drove that in 2022? Were you building some ducks? And just thoughts on will that shift a little bit as we think about 2023 because you have a pretty robust program? production growth outlook?

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, and so a lot of it's just the timing of the pads, completing the pads, and then working through the completion, you know, timing. So with only two rigs, you know, you're going to 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. So 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 Jeffrey Lamujan with Tudor Pickering, your line is open.

Hey, good morning, everyone. Appreciate you all taking my questions.

You bet, Jeff.

Yeah, thanks for speaking to me. And just a couple here, follow-ups on Egypt. Obviously, some solid execution there, especially relative to earlier in 2022, as you all highlighted, that's showing up. And production results, as we all saw. So as you think about the 2023 guide, I was hoping you could speak to 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 and 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 tracking execution from here on the 2020 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. 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. But, you know, I think we've given very realistic and good guides, you know, for 2023. And I think there's good confidence from the team. I know I sure asked that question and it's the response I get and the response that I'm, you know, comfortable to relay.

Okay, great. And then I guess just on operations and efficiencies, again, you know, obviously improved quite a bit as you move through 2022. Just want to get a sense for what you're focusing on from that perspective and, you know, what kind of running 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 seismic and some of the exploration that we're doing there. And so within those areas, we should see improvement as we drill more wells and, you know, areas you've drilled before. Yeah. You know, you're seeing some of that. And, you know, the big thing is, 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. And you saw great progress on the safety front. We're going to 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 Christman for closing remarks.

Yes, thank you. And before closing today's call, I want to leave you with the following thoughts. First, I want to 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. Lastly, in Suriname, the JV has accelerated appraisal at Crabdago, 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.