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spk01: Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corp first quarter 2023 earnings conference call. If at any time during this call you need assistance, please press star zero for the operator. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
spk00: Thank you, Joelle. Good morning, everyone, and thank you for joining us on our first quarter earnings call today. Joining me today is Roger Jenkins, President and Chief Executive Officer of along with Tom Morales, Executive Vice President and Chief Financial Officer, and Eric Hambly, Executive Vice President of Operations. Please refer to the informational slides we've placed on the investor relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves, and financial amounts are adjusted to exclude non-controlling interest in the Gulf of Mexico. Cautionary statements. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2022 Annual Report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger.
spk10: Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. On slide two, Murphy continues to deliver a strong value proposition to our shareholders. Our ongoing execution excellence across our significant offshore backlog and over 1,000 oil-weighted onshore locations will ensure that we remain a long-term, sustainable company. We operate safely with a focus on continual improvement in our carbon emissions intensity. Our offshore competitive advantage is reinforced with our significant recent project success at our Khaleesi-Mormont Samurai fields in the Gulf of Mexico. Murphy also has an ongoing exploration portfolio as we're in process of a three-well program operated this year. We continue to generate strong cash flow. We've been able to more than double our long-standing dividend from 2021 as well as significantly reduce long-term debt. On slide three, as we advance our priorities to deliver, execute, explore, and return, we remain focused on achieving our $500 million debt reduction goal for 2023 as we execute Murphy 2.0 of our capital allocation framework. The recognition of our debt reduction efforts over the past two years, along with our great execution success, especially in the Gulf of Mexico, We recently received a credit rating upgrade to BB positive with a stable outlook from S&P Global. Our efforts on maintaining strong well performance and uptime led to Murphy's first quarter production volumes of 172.5 thousand barrels equivalent per day, exceeding the upper end of our guidance. We executed our onshore well program as planned with 15 operated wells online. In the Gulf of Mexico, our team brought online the Samurai 5 well, At the end of the quarter, we've been able, and the well has produced above expectations this past month. Murphy also celebrated a significant milestone recently with the one-year anniversary of achieving first soil at Kings Key. I'm pleased to say that the gross cumulative production on that facility in the first year was more than 30 million barrels equivalent. On the exploration front, we disclosed today the success at the Long Claw Well, and we're awaiting results of two additional exploration wells later this year. We also added to our expiration portfolio with six blocks from the recent Gulf of Mexico federal sale. As we continue to support our shareholders through targeted returns, Murphy announced last month we'll be maintaining our quarterly dividend at 27.5 cents per share, or $1.10 on an annualized basis, which we know is the highest rate since 2016. On slide four, exceeding guidance for the first quarter across all of our assets, due to stronger well performance, production of 172.5 thousand equivalent per day, consists of 94,000 barrels of oil per day, which represents a 25% oil growth since the first quarter of 2022. Our highest first quarter production level since 2020. In the Gulf of Mexico, we produce nearly 4,000 barrels equivalent per day above our guidance, as well as 1,100 barrels equivalent per day above guidance in Tupper Montney, along with 3,400 barrels equivalent a day of positive impact in the Tupper Montany due to lower royalty rates. We realized $74 a barrel for our oil. We had a realized NGL price of near $26 a barrel, and that gas for us was 268 per thousand cubic feet for the quarter. I'm now going to turn the call over to our CFO, Tom Morales, for an update on our financials and sustainability efforts. Tom.
spk09: Thank you, Roger. Good morning, everyone. Slide five, our first quarter net income totals $192 million, or $1.22 per diluted share. Including after-tax adjustments, adjusted net income was $195 million, or $1.24 per diluted share. Our continued operational success generated strong cash from operations including non-controlling interest of $280 million, which also reflects $124 million of our contingent consideration payments made in the quarter. After accounting for net property additions, we had negative adjusted cash flow of $66 million, which is a reflection of our forecasted capital program being heavily weighted to the first quarter. The remaining $48 million of our first quarter contingent consideration payments were reflected in the financing activities section of the cash flow statements. These contingent consideration payments were related to two Gulf of Mexico acquisitions in 2018 and 2019 and were structured as revenue-sharing payments once certain thresholds were exceeded. The last revenue-sharing contingent payments were made in the first quarter as reflected in their financial statements. A final $25 million payment was made in April related to the one-year anniversary of First Oil at Kings Key, which fulfills all of Murphy's obligations on these transactions. Slide six. We maintained a high level of liquidity in the first quarter of $1.1 billion, consisting of our $800 million credit facility and more than $300 million of cash and equivalents. I'm pleased that Murphy recently received a credit rating upgrade to BB Plus with a stable outlook from S&P Global, reflecting our operational excellence and our commitment to debt reduction. Consistent with our priorities, we remain focused on achieving our $500 million debt reduction goal for 2023. Slide 7. As part of our operational excellence, we are delivering on key sustainability initiatives. Our operations team is successfully reducing emissions through a variety of techniques. For example, we are replacing diesel with natural gas in our drilling and completion operations and installing more effective vapor recovery units in our onshore facilities. Additionally, we are enhancing our water recycling and have recycled approximately 36% of our total frac volume in first quarter 2023 onshore completions. This represents a significant improvement from four years ago. Our efforts have been recognized. Murphy was recently named to Newsweek's Most Trustworthy Companies in America 2023, as well as Best Place for Working Parents 2023 by the Greater Houston Partnership for a second consecutive year. With that, I'll turn the call over to Eric, our Executive Vice President of Operations, to discuss our asset successes.
spk08: Thank you, Tom, and good morning, everyone. Slide nine. Mercury's first quarter Eagleford shale production averaged 27,000 barrels of oil equivalent per day with 85% liquids. We brought online 10 operated wells as planned in Carnes, which included two successful reef racks. Additionally, we had seven gross non-op wells come online in the quarter across our Tilden and Katerina acreage. For the second quarter, we plan to bring online nine operated Catarina wells and eight operated Tilden wells, plus two non-op wells in Tilden. Over the past few years, our CARNS program has included a couple of refract wells in conjunction with new development. I'm pleased that our 2023 wells achieved a 10-time production increase and delivered higher post-refract rates than the wells delivered at initial production. As you can see on our chart reflecting Carn's Lower Eagleford Shale performance, our average 250-day cume per foot demonstrates the improvement we've seen with our enhanced completion design, which we've highlighted in previous quarters. Slide 10. In the Tupper Montney, Murphy produced 292 million cubic feet per day in the first quarter and brought five wells online as planned. Our well delivery program continues in the second quarter with three planned wells. We maintain a price diversification strategy for a portion of our volumes that are not protected with fixed price forward sales contracts. For the first quarter 2023, we sold approximately 17% of our volumes at Malin, Chicago, Ventura, and Don pricing for an average $6.65 US per 1,000 cubic feet. No volumes were exposed to ACO prices in the quarter. As a result of this risk management strategy, we received an overall realized gas price of $2.59 U.S. per thousand cubic feet for the first quarter, which was approximately 9% above the ACO average. Slide 12. Murphy produced 90,000 barrels of oil equivalent per day with 80% oil across its offshore assets in the Gulf of Mexico and Canada. Late in the quarter, we brought online the Samurai 5 well and have seen production exceeding expectations. We are excited to have recently celebrated the one-year anniversary of achieving first oil at Kings Key and note the significant accomplishment of more than 30 million barrels of oil equivalent gross cumulative production in the first year. We also recently had another record gross production level of 126,000 barrels of oil equivalent per day, and we continue to average 97% uptime. Our operating partner at Terra Nova continues to work on maintenance and commissioning activities in Newfoundland, and Murphy maintains the view that it will be back online at year end. And with that, I will turn it back to Roger.
spk10: Thank you, Eric. On slide 14, we're pleased to announce we have today that Murphy's operator drilled a discovery at the Long Claw Exploration Well in Green Canyon 433 in the Gulf of Mexico. This well will be a tieback to our Kings Key facility. We found 62 feet of net oil pay and are evaluating results. The well just finished here just recently. Murphy held a 10% working interest while drilling long haul and received a 4.5% carry after casing. So after our election, we will hold 14.5% working interest in this well. As previously disclosed, Murphy temporarily suspended drilling on the Osho number one exploration well in Atwater Valley 138 in the Gulf of Mexico. We highlight that this is no indication of potential well results, and Murphy intends to resume drilling in the third quarter of this year once the necessary managed pressure drilling equipment and required permits have been received. Our operated Gulf of Mexico exploration program continues this year with our third well, Chinook 7, which is located in Walker Ridge 425. We spud this well just two days ago. We anticipate the cost of $48 million net to Murphy. We estimate a mean to upwards gross resource potential of 50 to 120 million barrels equivalent from this well. If successful, we intend to tie this well into our nearby Murphy operated Cascade Chinook FPSO. As we turn to slide 16 on capital and production, as disclosed in our news release earlier this morning, We're maintaining our 2023 CAPEX guidance range of $875 million to $1.025 billion. We also reaffirm our full year 2023 production range of 175 to 183 and a half thousand barrels equivalent per day, which is 55% oil. Overall, this achieves a 10% oil growth from full year 2022 and 7% total production growth. For the second quarter, we forecast an estimated production range of 173 to 181,000 barrels equivalent per day with approximately 54% oil and 60% liquid volumes. Our forecast accrued capex for the quarter will be $320 million. On slide 17, as announced in 2022, Murphy has a multi-tier capital allocation framework that allows for additional shareholder returns beyond our quarterly base dividend while advancing toward a long-term debt target of $1 billion. We maintain a broad, a board rather, authorized initial 300 million share repurchase program, allowing Murphy to repurchase shares through a variety of methods with no time limit. As of today, we have not executed any repurchases under that authorization. On slide 18, we continued our discipline strategy to deliver, execute, explore, and return. and our near-term plan is to reduce debt by $500 million this year, assuming a $75 per barrel oil price, with approximately 40% of operating cash flow reinvested annually through 2025 based on an average capital amount of $900 million per year. We forecast that this will maintain an average 55% oil weighting, with production averaging 195,000 equivalents per day representing a combined annual growth rate of 8% through 2025, while also supporting our targeted exploration program. As part of this plan, offshore production will be maintained at an average of 90,000 to 100,000 barrels equivalent per day in that period. Overall, we continue to utilize excess cash flow as we execute our plan of enhancing payouts to shareholders through dividend increases and share buybacks as laid out in our capital return framework. Longer term, in 26 and 27, we see Murphy maintaining sustainable business and targeting investment grade status. We forecast average annual production of approximately 210,000 barrels equivalent per day at 53% oil weighting. Additionally, our ongoing reinvestment rate will remain low at 40% of our operating cash flow, and we will have ample free cash flow generated from this plan to fund further debt reductions in our capital allocation framework and enhance shareholder returns, as well as fund high returning investment opportunities. On slide 19, on strategic priorities, looking forward for the remainder of 23, Murphy is well positioned to execute our Murphy 2.0 Capital Allocation Framework Plan. Our strong Gulf of Mexico business continues to lead the way with great execution and well performance, and is supported by our multi-decade sustainable onshore business. We also have two additional key exploration wells to drill this year and look forward to reviewing those results with our investors. In closing, I'd like to thank our great employees for their hard work this quarter as we beat across the board on every number, and we've very successfully executed our plans with their efforts. Now I'll turn the call over to everyone for their questions. Thank you.
spk01: Thank you, ladies and gentlemen. We will now begin the question and answer session. Should you have a question, please press star followed by the one on your touchtone phone. You will hear a three-tone prompt acknowledging your request and your questions will be pulled in the order they are received. Should you wish to decline from the pulling process, please press star followed by the two. If you are using a speakerphone, please lift your handset before pressing any keys. One moment, please, for your first question. Your first question comes from Arun Jayaram. with JP Morgan. Please go ahead.
spk07: Good morning, Roger.
spk10: Good morning, Maroun.
spk07: Yeah, good to hear from you as well. Roger, I was wondering if you could give us a little bit more details on the 2023 program in the Gulf of Mexico. You highlighted the drilling of Chinook No. 7, as well as a planned return to Oso. And perhaps you could also just discuss some of the inventory you added through the recent lease sale in the Gulf of Mexico.
spk10: Yeah, thanks for that question about all that. We had a very good lease sale. We just finished up this Long Claw well, just finished drilling the well not even a week ago or five or six days ago, which we had success. Oso is a well we'll be returning to in the third quarter. We have a plan from our team to execute that well with some additional equipment that we need. I would also comment that the Oso area was quite active in the lease sale. There's a new data set being shot in that region. And it was a lot of activity around that Oso area. We were also active there and were successful there. We had a very successful lease sale in that area and up near the Delta House area where we had a lot of competition. We were able to have success on all of our competitive blocks but one. So really good lease sale and a big, nice inventory, especially around Delta House and especially around Oso. The Chinook Wells is a well we've been planning for a very long time. This is a significant area. undrilled fault block near a Cascade Chinook field that we purchased from our pork farm to JV rather with Petrobras years ago. It comes with an FPSO that sits in that field, a very highly successful FPSO with incredible cost structure and uptime, a real asset for us. And we've had this well in our books, had to work out some things with our partners and announced by that well yesterday and real excited about that well. Uh, we do have a backlog of other opportunities that I'll have Eric address involving development here. Eric wants you to update a room on that.
spk08: OK, thanks Roger. As we highlighted on our last quarterly call, we have been working over the last several years with some of our recently acquired fields and have come up with a number of projects. And as we highlighted in our last quarter, we have quite a nice running room of offshore projects that will perform over the next five to seven years, including 26 projects with 125 million barrels of total resource that have a break even of less than $35 a barrel WTI. So we're pretty excited about our development opportunities, as well as the exploration opportunities that Roger highlighted.
spk10: But with the ongoing activity of room, we will be bringing on Dalmatian well later this year and drilling and hopefully completing a Marmalard well that probably just really can't flow much right at the end of the year.
spk08: Should flow early in the 24th.
spk07: Great. And Roger, I wanted to see if you could give us an update on your plans and non-op and operated plans in Canada. You highlighted two wells at Hibernia. And can you give us an update on what you're hearing from the operator at Terra Nova? I think you expect the project to start online by year end.
spk10: I would normally let Eric handle this, but it's quite simple. We've reviewed the project, and we believe it can flow at year end, and we believe it's better to provide investors a timing rather than an open-ended type dialogue. And we're hopeful to work with them more ahead and engage with them. And we feel that that project will flow at near year end. It is not going to be a significant part of our volume if it does not, but that's our status on that today. Hibernia, all-time great field for us and have a couple wells there planned. As we frame and talk about Terra Nova in your commentary this morning, you noted about the well-discussed Terra Nova. We have made $1.2 billion of free cash flow at Terra Nova at only a 9% working interest, and now we have a larger working interest that's funded primarily through a government deal. This is an incredible project. This project will come online. This project will have incredible high return. Hibernia II made almost $3 billion of free cash flow itself. So these are significant, successful, long-term fields for us, and we're well positioned there to make a lot of free cash flow in East Coast Canada.
spk07: Great. Thanks a lot.
spk01: Thank you. Your next question comes from Neil Dingman with Truist. Please go ahead.
spk02: Thanks for the time. Roger, my first question is also on offshore. I'm just wondering, you've been successful I guess last year and even other years just on adding very creative working interest and other things like that offshore. I'm just wondering, could you talk about kind of what Arun was asking? I'm wondering how you would balance, you know, you've got obviously the positive things going on at Kings K. You've got some interesting exploration. I'm just wondering how you would balance maybe seeing some additional working interest or other opportunities within those two.
spk10: That's a good question, Arun, and thank you for asking about our successful efforts in the Gulf of Mexico. We really don't have a hot running working interest purchase today, quite frankly, and we're really executing our backlog of offshore wells and our longstanding inventory of onshore wells along with the framework that I, not the capital allocation framework, but our long-term plans that I disclosed just a few minutes ago in my commentary. We want to keep that capex and that range continue to have this modest growth and will be picking and choosing between our long-term projects in the Gulf and our very significant success in Eagleford as well and be maintaining these oil rates and just have multiple ways to make the same return and real proud of our inventory both off and onshore. We've got offshore inventory too, and Eric's done a great job at pulling it together. And we're going to be executing it like on slide 12 this year. There'll be another slide like that next year. And we're happy with where we are on having the assets to sustain our plan and be successful. And we have them.
spk02: Great point. And then, Roger, maybe for you or Tom, just second on free cash flow allocation. I believe your debt targets are on a gross, not net basis. So it really looks on reducing debt instead of just adding cash to the balance sheet. And so- I know in the past you've talked about maybe wanting a minimum cash balance of, I don't remember, about $400 million or so for M&A and discoveries. So I'm just wondering, given what's going on with prices and your announced recent discovery, I'm just wondering, and I know you've got this Murphy 2.0, would you all consider foregoing one to two quarters of debt reduction in favor of a cash build? Or how do you sort of see that plan going forward?
spk09: No, the way we've been thinking about it, Neil, is we're going to really focus on getting to that long-term debt target. So our priority right now is to any adjusted free cash flow. We'll stick to the framework and focus on reducing that debt. As you saw in our financials, we are kind of front-loaded here with our capital, so it's probably more of an activity we'll see in the second half of the year starting to – starting to reduce that debt with any adjusted free cash flow we have.
spk10: I have a little bit of color to add to that, Neal. I think it needs to be pointed out. If you look at our cash flow statement today, yes, our cash went down about the same amount of the contingent payments. So we're talking about paying contingent payments into very successful M&A, which there was a revenue sharing, which we received the other half. Also, all this M&A is completely paid out including acquisition, have been paid out. Khaleesi Mormont's been paid out. Delta House has been paid out. So we have paid out assets. And if we have a severely front-loaded capital and without contingent payments would have had cash flow neutral, I think that's very positive for us. It sets us up in the second half to really execute on this framework that we have. That's a great point. Thanks, Roger. Thank you, Neil. Good hearing from you.
spk01: Your next question comes from Paul Chang with Scotiabank. Please go ahead.
spk06: Hi, good morning, guys. How are you doing? A number of quick questions. Maybe the first one, just administrative, that the APO contingency payment, when is it going to show up in the cash flow statement? Is it in the financing activities or is it in the cash flow from operations?
spk10: I'm sorry, Paul, you mean the contingent payments have already been paid. There's one additional payment, as we disclosed in our release, of $25 million. We've already paid it this month. Where is it, Tom? It will be in operating cash flow, I would assume. It will also be split a little bit between operating. It will be split between financing and operating. That's due to the original setup of the M&A deal and our accounting, Paul.
spk06: Okay.
spk10: But that's over. After that, this stuff is over, Paul, for all of us.
spk06: No, I understand. We're just saying that because I think that investors will be looking at the CFFO number more closely, typically. So we want to know whether that 25 million is going to be in there or just going to be in the financing activity line. Second one, Roger, that in post-2026, once you get to 200,000, 220,000 billion per day kind of range, What's the subsisting CAPEX requirement going forward?
spk10: I believe it's disclosed on that slide, Paul. Turn to that, Megan, please. In the 26-27 period, I would anticipate it to be in the similar level that we are on the left-hand side of that slide, in the 900 level, not 950, is my expectation for that, Paul.
spk06: Okay. And then a final one for me. On the longer term, how's your marketing strategy for money? I mean, right now that you have majority of them sold under fixed long-term contract and then the rest is to the different part in the U.S. and no spot exposure. Should we assume that that will be essentially the strategy going forward?
spk10: I'm going to let Eric give you color on that, Paul, please.
spk08: Okay, Paul. We have, as you noted, we, through 2022 to 2024, put in place a number of fixed forward cells related to our Tupper Montney project. So we, as you know, we increased the capacity of our plants there by 200 million cubic feet per day. And we've had a multi-year program of adding a slightly higher level of activity to get those plants full. which we expect probably by the second half of 2024. In order to support that additional capital allocation to the asset, we put in place some fixed forward sales to make sure that we would generate free cash flow from the asset while growing. If you look beyond 2024, we are very unlikely to put in place fixed forward sales like that, but we are likely to maintain a diversification strategy where we've proven over quite a long time now, a decade or so, that we've been able to get enhanced prices by diverse sales into various U.S. markets like Malin, Chicago, Ventura, and Dawn. That's something that will likely feature in our program going beyond 2025. And then we're also looking opportunistically to participate in any kind of value creation that might be driven by LNG projects coming online in Canada or additional gas that needs to come into the Gulf Coast of the U.S. for LNG. So we'll evaluate all of those and have sort of a diverse strategy that maximizes our free cash flows.
spk06: Just curious that will you sign long term contracts or that is really going to be decided on a month to month basis in terms of which market you're going to sell to?
spk08: What I would expect there, Paul, is a combination of contracts that are based on locking in a differential with transportation from ACO to those diverse markets and other different kinds of arrangements that we can find the best outcome, best deal.
spk06: Okay. Thank you.
spk01: Your next question comes from Neil Mehta with Goldman Sachs. Please go ahead.
spk05: Good morning, Neil. Yeah, thanks. Good morning, Roger. Congrats on a good quarter here from an execution standpoint. I know you spent a lot of time talking about 2023, and it's early to talk about 24, but Yeah, real early. Yeah, real early. I recognize that, but I would imagine there are some moving pieces that you want us as an investment community to get our heads around as it relates to production. How should we – any early thoughts and guidance you can provide on 24 at an asset level would be great.
spk10: Well, thank you, Neil, for that question. Our long-range plan is not even Memorial Day, Neil. I try to gauge that. questions on holidays. We just finished Easter here. As for our page that we have here, we have an averaging CAPEX shown in our deck here today around 900. That means that CAPEX next year at this time and in that plan was a little bit less than this year. We'd hope to keep that similar to what we have this year. We do have a lot of backlog of offshore. We do have success today at Long Claw that will take the place of some of our backlog, if you will, at the point of when we want to do that. And so I would say it's a similar year to next year with higher production because we'll have all of our new backlog wells online, Dalmatian this year, Marmalard next year, and I'd assume it'll be a year similar to this with higher production, higher oil production, and higher overall production.
spk05: Thanks, Roger, for indulging me there. The follow-up, there's been a lot of talk about offshore cost inflation. We're seeing some early signs, hopefully, of deflationary forces in U.S. land, but offshore, still a lot of upward pressure. So can you talk about how you're mitigating it, and are you seeing any green shoots when it comes to the inflationary pressures?
spk10: Yeah, thanks, Neil. We've been preparing and I'm going to let Eric speak to you about that this morning.
spk08: Okay, thanks. Neil, the big driver for our costs for offshore is really rig rate. And we're sort of advantaged this year, and we're really happy with how we're set up for 2024 into 2025. So for about half of our program offshore in 2023, we have a significantly below market rig rate, which we locked in, so around 300,000 a day. The rest of the program, we have locked in pricing all the way through the end of 23, 24, and the first part of 25 at what is effectively market rate right now, which is around $430,000 a day for a drill ship. So we're pretty happy with that, and that should be the main component of something that could be inflationary for us. We have it locked in through early 25. Really happy with that.
spk10: Good stuff, guys. Thank you. Thank you, Neil. Appreciate it.
spk01: Your next question comes from Charles Mead with Johnson Rice. Please go ahead. Good morning, Roger.
spk04: To you. Good morning. I wanted to ask a question about these Carnes refracts. So it's really intriguing to me that you had higher IPs than the initial completion. But I wonder if you could add a few more coordinates to that. And I'm thinking... what's the decline profile look versus the original decline profile and how maybe the completion design or intensity versus the original completion and whether you're planning on doing more of these in 23.
spk10: Thank you, Charles. Eric's got it, came out with this plan. I'm going to let him tell you about it.
spk08: Okay. Thanks, Charles. We've identified 220 wells across our Eagleford shale position in which we think are likely to be good candidates for refracts. And the way we came up with that was we looked at wells that were initially fractured with less than 1,200 pounds per foot of propent. If you compare that to our current completion design of 2,800 to 3,400 pounds per foot, they look quite a bit under-stimulated. Over the last three years, our refract activity has been focused in CARNs and associated with new developments. So we go into an area where we plan new wells and we refract old wells, which we think that that's helping improve the performance of our new wells. And also, as we highlighted on our call today, we're getting nice production uplift and reserve recovery from those refracts. They're pretty exciting. We're seeing rates go from 15 to 20 barrels a day to up to 1,500 barrels a day initially. That's not an IP30. That's more of a peak. The decline profile is not that dissimilar from initial production from those wells when they first came online, maybe seven or eight years ago. So it looks like a good opportunity for us. What we do in those wells is we run a four-inch casing. We go and perf and frack kind of like a new well, just a little bit skinnier hole. And we've had great success with it. We're really excited. We're currently evaluating what might become a standalone program to address that 220 well inventory of refracts. That's not been our current mode, but that's something that we're looking at. Hope that helps you give a little background on what we're trying to do there.
spk04: That's a lot of great detail. Thank you, Eric. And my follow-up question, Roger, is about the King's Key program. the the kinks key facility and i went back and looked and and uh i guess the name played on that as originally designed was more like uh 102 uh mboe a day and so you guys are you know something north of 20 percent uh over that with this rate you disclosed today so are you guys what should we expect going forward it would seem to me that you're kind of you're kind of knocking up against the ceiling of what that what that facility could do and perhaps we should expect some kind of reversion back to main plate capacity over time, but perhaps that's not the case. I wonder if you could elaborate on that.
spk10: Thank you, Charles, for asking that question. It's a big home run field for us, one of the greatest in company history for us. It's going to be difficult, very difficult to produce more than that headline we had today, our equipment's running at the max. So, keep in mind that when we purchased this project and executed this project through COVID, that there's another field in the Gulf called Delta House. It's a very similar facility. It has multiple fields flowing to it that we also operate. And that field also has been able to go over nameplate. And our team was able to learn from that as we operate that and take this over nameplate. We're probably not going to see production levels from that. But we're very happy about where we are. We have to also keep in mind that Samurai is a field that's 50% working interest for us. And when Samurai does well, we do well. And the field's doing well and going to be on plateau here into 2025. And it's going to be some additional probably things that we're finding to do in that area. Samurai gets better and bigger every day. So big home run ball probably can't make much more production than that. But that's a lot of production out of eight wells. So we're really, really proud of it. And thanks for noting that.
spk04: Thank you for the detail, Roger.
spk10: It broke up, Charles. I'm sorry.
spk04: No, I was just saying thank you for that detail. That's it for me.
spk10: I thought you wanted more detail, Charles. I'd say, wow.
spk04: Another time.
spk10: Appreciate you calling in. Another time. Appreciate you calling in.
spk01: Ladies and gentlemen, as a reminder, should you have a question, please press star followed by the one. Your next question comes from Leo Mariani with Roth MKM. Please go ahead.
spk10: Good morning, Leo.
spk03: Thanks for calling in. Yeah, morning. I was hoping to get a little bit more color around the exploration program here in the Gulf. Just on the long claw well, you guys announced it as a discovery, but at the same time, I guess you said you're still evaluating it. It's got 62 feet, I guess, of net pay, which I know it's not the only metric, but doesn't seem enormous at this point. Just trying to confirm, is this, in fact, definitely a discovery, just given that it sounds like it's a A close subsea tieback probably won't require a lot of capital. And then just on the Chinook well, I wanted to see if we can get a little bit more color in terms of kind of rough drill time on this and what the risk profile on this thing is. Is this a true exploration well, kind of one in five type well in terms of the expectation? Just any color on it would be great.
spk10: Thanks for that question, Leo. No, absolutely. When we say a well is a discovery, we anticipate on producing that well. And we anticipate increasing our working interest on that well. Uh, it's, uh, the issue is the size of it, not issue is we're working it. I'd say it's a 10 to 20 million barrel discovery, but you're talking about a 50 yard tie back from here to my office to, to flow this well into one of the most successful platforms in the Gulf with manifolds pipes in place. So the economics of this similar samurai, which are incredible, uh, this will have a, uh, incredible economic and also. As we operate other fields and operate Kings Key, a new set of well not involved with the original field will lower the operating expenses across the whole platform for us and wells. This is very positive for us. Is it a massive oil field? No, but we can make a lot of money and do well here and work with our partners. And we were able to be carried in the well a little bit. And we're hoping to be able to do that in other places because we're a top executing company. Leo in the Gulf. On to Oso. It is not Oso, I'm sorry, Chinook 7. It is in a field that's been drilled many wells there. You can see the number 7, if you will. I would say it's a little better than a 1 in 5 exploration well. It isn't a totally undrilled fault block. A lot of these major Wilcox fields, such as St. Malo and also here Cascade Chinook and many others in the Gulf, have two big features to them with a large fault down the middle of the field. This so happens to have not been tested. We looked at this and compared it to other wells that have been drilled on both sides of major faults through these facilities, I mean, through these type plays. And we have a big, nice well to drill here. It can make this project last out to 2040. The FPSO there is a very, very highly operated, efficient FPSO. We can move the crude off that FPSO where we need to on the Gulf Coast with tankers. So it comes with positive differentials and many positive things for us. So it's near the field, but in a totally untested fault block. And we're very happy to be drilling that well and have a chance to, again, add more to our backlog. the well could get very large in size, requiring multiple wells if successful, or it could be a simple tieback. So, real happy about it, and thank you for asking us about it. All right, that's helpful.
spk03: And then just on the sort of, you know, free cash flow uses here in the second half, it sounds like you're very focused on paying down debt. You know, I imagine that there's probably going to be some takeouts, you know, of some of these existing bonds, kind of like you've done in the past with some tenders here. But just in kind of light of sort of lower oil prices here, does this make the share buyback kind of, you know, fairly unlikely here in 23 with the focus on debt reduction that we need oil prices to kind of go up before maybe you buy back shares? I mean, just kind of talk about the dynamic between those two.
spk10: I'm going to let Tom add all the color, but our framework, as we set up, has a portion to buy back or advance returns, which we assume to be buyback with debt reduction. So we can end up with less if oil prices are lower, but there's no plan to not buy back at all and due to all debt due to this pullback with the Fed and all that today, Leo. And I'll let Tom give you some more information on that.
spk09: Yeah, that's basically it. Leo, we'll stick to our framework, and as we get into this next phase here, it's definitely going to be splitting between 75% going to debt reduction and 25% going to share repurchase. So with this pullback in oil prices, maybe the quantums will be a little bit smaller than what we would have planned at $75 WTI, but that still is what we're planning to do following our framework, 75-25 between debt reduction and share repurchase.
spk03: Okay, that's helpful. And then just on your production volumes, obviously you've got, you know, second quarter guidance here. I very much appreciate the detail there. But just kind of in the rest of the year, can you kind of help us out a little bit with kind of the high-level sort of cadence here? Do we see Gulf of Mexico volumes in 3Q maybe kind of flat to down with just hurricanes, you know, likely here in terms of the way you guys are thinking about it and then kind of a nice ramp in 4Q? And then I imagine that onshore you're going to see the The nice ramp in 3Q is you get the benefit of kind of more wells coming on. Just kind of any help on production cadence in third quarter and fourth quarter, just kind of the big moving pieces here?
spk10: Well, if you look at our guidance today for the second quarter, making a little bit less in the Gulf of Mexico, we have to shut in Kings Key for a few days here coming up to do a turnaround of some equipment we need to update there. And then actually in our lineup, the third quarter, while under a big hurricane downtime still is higher than the second quarter and a big end of the year. So I'd say it's, you know, right now we've got it, you know, 80 to 81 here in the second quarter, probably trying to get close to 83 in the third, a little higher possibly, and maybe 90, a little more 90 in the fourth quarter there, Leo.
spk08: Yeah, Leo, just a bit of background. I think we've noted before that our onshore program is pretty heavily weighted from new wells coming online in the second and third quarter so you see more growth onshore heading into the third quarter and then more growth offshore heading into the fourth quarter as we bring online dalmatian terra nova uh the dalmatian new well dc 90 well and terra nova restart along with less weather downtime assumed in the third quarter so third fourth quarters aren't that dissimilar from a total production rate with a little more growth from second quarter onshore in the third quarter and a little more growth offshore in the fourth quarter.
spk03: Okay.
spk10: Very helpful, guys. Thank you. Appreciate it. Take care.
spk01: Your next question comes from Paul Chang with Scotiabank. Please go ahead.
spk06: Hey, guys. You're back, Paul. Yeah, just want to clarify. Eric, when you're talking about the refract dose opportunities, 220 wells, That's not included in your current 1,100 wells in the Eagle Fund, right?
spk08: That's correct. Those are wells that are already producing. They're not included in our 1,100 wells of remaining Eagle Fund inventory to be addition to that.
spk06: All right. Thank you. And what you're just curious that in long haul, you only have 10% interest and you're the operator, which is quite unusual for someone with a small percentage like that to be the operator. Is there any game plan in there that will be able to have some arrangement for you to boost the interest or that, I mean, this interest is, I mean, I'm just curious that why you would take the operatorship there?
spk10: Thank you, Paul. You can operate things at 10%, Paul, when you're real, real good. And we're real, real good. So that's kind of how that goes. This was a long-term prospect that was known. When we purchased the field, Khaleesi-Mormont, and we had our significant discovery at Samurai Next Door, several of the partners that are in the field owned this opportunity. They came to us to participate in the well. And if you notice in my commentary, in my script commentary, we had an ability to increase our working interest post the well being cased, which we're going to do. So we have an ability to go up to 14.5%. This well is this team that built this prospect really respects our company as an operator. We also have this work going on up in the middle of our most valuable field that we've ever owned probably. And so we want to operate and ensure operations out in the middle of Kings Key and Samurai. This is located very near. It's also very near. We decided to put the well near one of the production manifolds. So our equipment and a lot of our company's value is there. So we wanted to operate even at a smaller working interest. And, uh, we see it as an ability to control the field, operate the field efficiently, safely. and increase our working interest due to our operating skill, and then lower the operating expenses of the facility. So it's a win across the board for us, and the partners are a great relationship, these partners, and they see us as a good operator, and we execute the well for them at a low working interest, and everybody wins today, Paul.
spk06: All right. Thank you.
spk10: Thank you.
spk01: There are no further questions from our phone lines. I would now like to turn the call back over to Roger Jenkins for any closing remarks.
spk10: Appreciate everyone dialing in today. Appreciate the questions from our key analysts today. It was good commentary back and forth. Really appreciate that support and that we're here executing another quarter. We're doing very well and very proud of how we're running our business today. And we'll be talking to you all soon. Take care.
spk01: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you disconnect your lines.
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