Good morning, ladies and gentlemen. And welcome to the Murphy Oil Corporation Fourth Quarter 2023 Earnings Conference Call and Webcast. Please note that there are instructions from the operator.

Good morning everyone and thank you for joining us on our fourth quarter earnings call today. Joining me is Roger Jenkins, President and Chief Executive Officer along with Tom Mireles, Executive Vice President and Chief Financial Officer and Eric Hambly, Executive Vice President, Operations. Please refer to the informational slides we have 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. 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 Jenkins.

Thank you, Kelly. Good morning everyone and thanks for listening to our call today. As we turn to slide two, I'd like to highlight Murphy's ongoing focus on our priorities to Delever, Execute, Explore and Return throughout 2023. With another strong year of production and excellent execution, we achieved our $500 million debt reduction goal for the year and have reduced debt by $1.7 billion since the end of 2020. We produced 186,000 barrels equivalent per day for the year with 52% oil volumes. During the fourth quarter, we began procuring equipment for the Lac Da Vang field development in Vietnam and production resumed at the non-operated Terra Nova field offshore Canada with wells scheduled to ramp up production through the first quarter of this year. In the Gulf of Mexico, we acquired an 8% working interest in the Zephyrus discovery for $13 million in the fourth quarter. For the year, we achieved a 139% reserve replacement with preliminary total reserves of 724 million barrels equivalent and approximately an 11-year reserve life. In exploration, we were named a paired hybrid and 8 exploration blocks in the Gulf of Mexico federal lease sale 261 held last fall. We also continue preparing for our 2024 planned exploration wells in the Gulf and Vietnam and advancing seismic reprocessing projects in the Gulf of Mexico and Cote d'Ivoire. Due to significantly reducing debt prior to 2023, we're able to reach Murphy 2.0 of our capital allocation framework last year, representing a debt level between $1 billion and $1.8 billion. I'm pleased to say that we executed additional share repurchases totaling $75 million or 1.7 million shares at an average price of $43.42 per share in the fourth quarter. For the full year 2023, we repurchased 3.4 million shares for $150 million at an average price of $43.96 per share. As a result, we have $450 million remaining under our share repurchase authorization at year-end. I'm pleased to return to the share buyback mode, where we have purchased $1.8 billion of stock in the last 10 years. We announced earlier today a 9% quarterly dividend increase to $1.20 per share annualized back to our level of 2016 and look forward to targeting Murphy 3.0 as we continue delivering shareholder returns and reducing debt levels. On Slide three, Murphy's production averaged 185,000 equivalent per day in the fourth quarter, 94,000 barrels of oil per day. For the year, production of 186,000 equivalents with 98,000 oil per day. For the quarter, we realized over $79 a barrel of oil, reversing a slight premium to WTI. This is on a netback basis, as well as nearly $21 per barrel for NGLs and $2.12 per 1,000 cubic feet for natural gas. This led Murphy to generate $788 million of total revenue in the quarter. And for the full year, we realized over $77 per barrel for oil and generated $3.2 billion in revenue, excluding non-controlling interest. On Slide four, we achieved great year reserves. Our preliminary proved reserves totaled 724 million barrels equivalent, representing a 139% reserve replacement ratio from year-end 2022. This increase is due in part to the additional 13 million barrels equivalent of proved reserves for the Lac Da Vang field in Vietnam as well as AECO natural gas price changes. Total proved reserves in 2023 were 57% proven and 41% liquids weighted, and we have a proved reserve life of 11 years. Overall, I'm pleased to say we've maintained our proved reserves since 2020 with an average annual CapEx of approximately $1 billion, excluding non-controlling interest and including acquisitions. It must also be considered that our strong reserve outcome is based on oil prices that were $15 per barrel lower than in 2022. Furthermore, our reserves, excluding Syncrude, are 27% higher than a decade ago when we became an independent E&P company. I'll now turn the call over to our CFO, Tom Mireles, to update us on our financial results. Tom?

Thanks, Roger, and good morning, everyone. Turning to Slide five. In the fourth quarter, Murphy reported $116 million of net income or $0.75 per diluted share, $140 million of adjusted net income or $0.90 per diluted share. Due to another strong operational quarter, we achieved $414 million of adjusted EBITDA with $219 million of accrued CapEx, excluding non-controlling interest and acquisition-related CapEx. Murphy continued to return cash to shareholders in the fourth quarter by repurchasing $75 million of common stock at an average price of $43.42 per share. For the year, we achieved $709 million of adjusted net income and $2.1 billion of adjusted EBITDAX. Accrued CapEx totaled $1 billion, excluding non-controlling interest and acquisition-related CapEx. Further, our 2023 G&A expense was the lowest in more than 20 years. On Slide six, as we discussed, as of December 31, 2023, we had $1.3 billion of senior notes outstanding and $1.1 billion of liquidity, and our next senior note maturity isn't until December 2027. Since year-end 2020 and including our $300 million debt reduction goal for 2024, we will have reduced our total debt by 66% by year-end 2024. From 2020 through 2023, this resulted in about an $84 million reduction in annual interest expense on long-term debt. I'm pleased to say that during this time, and more recently in alignment with our capital allocation framework, we have been able to increase our quarterly dividend and return to our 2016 level of $1.20 per share annualized. Since year-end 2014, Murphy has repurchased 24.8 million shares or 14% of the shares outstanding at that time. While we are pleased to be back to our 2016 level on the dividend, investors are also advantaged by our balance sheet. Our net debt has improved 50% since 2016, and it's the lowest since before 2012. Slide seven. As we first introduced a little over a year ago, our capital allocation framework defines three debt thresholds and corresponding shareholder return allocations. We're currently in Murphy 2.0 with $1.3 billion of total debt and are targeting $300 million of debt reduction this year to reach Murphy 3.0. At that time, shareholder returns will increase to a minimum of 50% of adjusted free cash flow. Slide eight. At Murphy, we remain mindful of taking actions that benefit all stakeholders, and we are proud of our ongoing environmental and community stewardship achievements. This focus is at all levels of the organization and metrics such as greenhouse gas emissions intensity, safety and spill performance are all included in our annual goals. I'm proud of what we continue to accomplish at Murphy and highlight that these efforts are recognized repeatedly with top quartile rankings by third parties. All of our improvements can be found in our sustainability report, which is available on our website. With that, I'll turn it back over to Roger.

Thank you, Tom. Let's look now at the quarter results and our onshore assets. We produced a combined 100,000 barrels equivalent per day with 30% liquids weighting in quarter 4 and in the Eagle Ford Shale, we produced 31,000 equivalents per day with 86% liquids. We brought on 3 non-operated wells in Tilden, which is all we had for the quarter. No wells were brought online in our onshore assets as well. In Tupper Montney, we produced 386 million cubic feet per day in the fourth quarter and initiated drilling a 10-well pad with 2 rigs. In Kaybob Duvernay, we produced 4,000 equivalents per day for the quarter, including 69% liquids. Turning to offshore in the quarter, Murphy produced approximately 84,000 equivalents per day in our offshore business, with 82% oil. The Gulf of Mexico production totaled 81,000 equivalents per day. We brought online the operated Dalmatian number 1 well in the quarter, as well as drilled, completed, and recently brought online the Marmalard 3 well. Also during the quarter, we acquired an 8% working interest in the non-operated Zephyrus discovery for approximately $13 million after closing adjustments. Offshore Canada, we produced 4,000 equivalents per day. The non-operated Terra Nova FPSO resumed operations during the quarter, and production is expected to ramp up this quarter in 2024. Looking at exploration, as previously announced, we expanded our exploration portfolio in 2023 with the addition of 5 key blocks in Cote d'Ivoire, and we gained seismic reprocessing and the side for the opportunities in these blocks, including advancing the field development plans for the undeveloped Paon discovery. In Vietnam, the Murphy Board sanctioned the Lac Da Vang field development project in the fourth quarter. Our two exploration wells planned in 2024 provide upside to this development, particularly as one well is very near the platform facility. Lastly, in the Gulf of Mexico, we were named a parent bidder on 8 blocks in the latest federal lease sale. These locations will provide near-field exploration opportunities close to existing assets. Now we'll dig into our capital and production plans for the year. On Slide 13, on the capital side, our plan is structured so that we can continue generating sufficient free cash flow to advance our capital allocation framework. We forecast a CapEx range of $920 million to $1.02 billion with nearly 60% of the spending in the first six months of the year. Overall, 85% of our capital plan is designated for development work, with 80% of this supporting operated activity. As we target Murphy 3.0 with our $300 million debt reduction goal in 2024, I'm pleased we were able to announce this morning a 9% increase in our quarterly dividend to $1.20 per share annualized. We're also targeting share repurchase equal to 25% of our adjusted cash flow for the year, and we believe these goals can be accomplished at a minimum oil price of $70 a barrel. On the production side for 2024, our forecast for the first quarter production range is 163,000 to 171,000 barrels a day, including 53% oil. This range is impacted by 13,000 barrels equivalent per day of total Gulf of Mexico downtime, as well as 2,000 barrels of oil equivalent per day of onshore downtime, including the Gulf downtime of 6,000 per day associated with the wells currently offline that are scheduled for workovers and will return to production in the first half of the year. This also includes 5,000 barrels per day for planned facility and downstream maintenance, as well as 2,000 barrels equivalent per day of downtime to repair damaged subsea equipment in the Mormont field in the Gulf of Mexico. For the full year 2024, we forecast a production range of 180,000 to 188,000 per day, including 52% oil volumes. This forecast includes approximately 2,000 barrels equivalent per day of assumed annualized Gulf of Mexico storm downtime and accounts for 2023 divestiture of some 1,500 barrels equivalent per day in non-core Canadian asset sales. Consistent with several years, our annual plan focuses on maximizing free cash flow, which has led to a first type weighted capital program. As a result, we have seen material production growth from the first quarter to the fourth quarter. Each year in 2024 is forecast to have a similar trajectory with production rising to nearly 200,000 equivalents per day in the fourth quarter, which will be our fourth year in a row of higher fourth quarter production. Now for more details on the individual assets, I'll turn it over to Eric, our EVP of Operations. Eric?

Thank you, Roger, and good morning, everyone. Slide 15. Our 2024 capital budget of $320 million for the Eagle Ford Shale supports a program of bringing online 19 operated wells, primarily in Catarina, as well as 18 gross non-operated Tilden wells. Additionally, we plan to drill 11 operated Karnes wells, which are scheduled for completion in early 2025. With ongoing utilization of our optimized completion design, we forecast 2024 production of 30,000 barrels of oil equivalent per day with 71% oil volumes. We recently contracted a new high-spec drilling rig from Patterson-UTI Drilling Company, LLC. While only one well has been drilled so far, we are extremely pleased with the results and hope to see advanced drilling efficiencies throughout the year. Slide 16. Turning to Tupper Montney. Our 2024 capital plan of $90 million includes bringing online 13 operated wells, all scheduled for the second quarter. We are drilling in this area today and are 85% complete on our first 10-well pad. We forecast an average production of 370 million cubic feet per day in 2024 with this plan and look forward to continuing our real-time frac optimization, which has helped us achieve some of our highest IP30 rates in company history in recent years. Slide 17. In Kaybob Duvernay, we have a $40 million capital plan for 2024 to support bringing online 3 operated wells in the second quarter as well as initiating drilling a 4-well pad late in the year. Overall, we forecast average production of 4,000 barrels of oil equivalent per day, with 67% liquids volumes in 2024. Slide 18. Our total 2024 offshore capital plan of $370 million supports bringing online operated and non-operated tieback wells in the Gulf of Mexico as well as progressing the non-operated St. Malo waterflood project, the Lac Da Vang field development project in Vietnam and the Paon field development plan in Cote d'Ivoire. Through 2024, we will bring 4 operated subsea tieback wells online, with the first being Marmalard 3, which came online earlier this month. Additionally, 7 non-operated wells are forecast to begin production this year. Combined, we forecast average production of 88,000 barrels of oil equivalent per day for 2024. Slide 19. As disclosed in our last quarter call, we experienced mechanical issues at 2 operated Gulf of Mexico fields in 2023. We have a rig currently on location at Neidermeyer, and the workover is expected to be complete in the second quarter of 2024. For the Dalmatian subsea safety valve repair, we anticipate completing this repair in the middle of 2024. We also have zone changes planned at 2 operated Marmalard wells in the first quarter of 2024. Additionally, earlier this year, we experienced an issue with subsea equipment in our Mormont field, and we'll be making that repair in the first quarter of 2024. The non-operated Lucius #9 well workover has been completed and the well is forecast to return to production shortly. Additionally, the previously disclosed non-operated Kodiak 3 well stimulation and zone addition is scheduled for mid-2024. Slide 20. As announced last quarter, our Board sanctioned the Lac Da Vang field development project in BLOCK 15-01/05 in Vietnam. We have allocated approximately $40 million of CapEx to the project in 2024 to support facilities construction. To ensure capital efficiency, the field will be developed in phases through 2029, reaching first oil in 2026. Overall, Murphy is targeting 100 million barrels of oil equivalent estimated gross recoverable resources, and we booked preliminary net proved reserves of 13 million barrels of oil equivalent at year-end 2023. We forecast the field will achieve gross production of 30,000 to 40,000 barrels of oil equivalent per day or 10,000 to 15,000 barrels of oil equivalent per day net to Murphy. The field is 96% oil, and we will receive a premium to Brent oil pricing. And with that, I will turn it back to Roger.

Thank you, Eric. As to exploration, our total 2024 exploration plan of $120 million supports the drilling of 2 Gulf of Mexico and 2 Vietnam exploration wells, which combined target approximately 120 million barrels equivalent on a net mean unrisked resource basis. Additionally, this plan funds related exploration costs and ongoing geological and geophysical work. In the Gulf of Mexico, we are participating in 2 Oxy-operated wells, which are forecast to spud in the second quarter of 2024; both of these opportunities are located near infrastructure. In Vietnam, in addition to the Lac Da Vang field development, which is ongoing, we are planning to drill 2 exploration wells in 2024, and I look forward to the upside possibilities that these material near-field exploration prospects provide. The rig has now been secured to drill both wells, beginning with the HSV exploration well in Block 15-2, which will spud in the third quarter of 2024 and target a mean upward gross resource potential of 170 million to 430 million barrels equivalent. We anticipate the exploration well in Block 15-1 to spud in the fourth quarter of 2024. This well is just to the southwest of our Lac Da Vang field development and will target a mean upward gross resource potential of $65 million to $135 million equivalent. Overall, these two exciting prospects gain further advantage from infrastructure provided by our nearby Lac Da Vang field. On Slide 23, in Cote d'Ivoire, we're excited about the initial work completed on our newest country entry, including initiating size and reprocessing and looking forward to advancing the opportunities across our five significant blocks. In 2024, we continue reviewing commerciality and field development concepts for the Paon discovery in Block CI-103, which is appraised with multiple wells by a previous operator. As part of the agreement on the block, we are committed to submitting to the government a viable field development plan by the end of 2025. Clearly demonstrated in 2021, 2022, and 2023, Murphy has done a tremendous job in reducing debt. We have built a strong, safe balance sheet for the company, resulting in a 0.7x debt to trailing 12-month EBITDA based on third quarter results. We've been able to accomplish this deleveraging of our assets and generate significant free cash flow, as highlighted by our peer-leading 13% cash flow yield and $23 per barrel of oil equivalent metric. I'm proud that Murphy is a leader in these attributes, and with reaching our $1 billion debt target later this year, which ties to one times EBITDA at a mid-40s pricing, we will be able to continue our effort to return cash to our shareholders with a much safer balance sheet and safer than our peers with no bonds to be refinanced in our business until late 2027. As we look to Slide 26, we maintain a very similar long-term plan to what was disclosed a year ago, as we now incorporate the LDV field development as well as higher exploration spending, all of which supports long-term oil production growth. Overall, we forecast to achieve our $1 billion debt target in 2024 with no additional debt maturities until 2027, and we accomplished this in part by reinvesting approximately 50% of our operating cash flow into our business. Our average annual capital spend of $1.1 billion will support a 5% CAGR through 2026, increasing production up to an average of 195,000 equivalents per day, approximately 95,000 of which will be oil equivalents per day produced in our offshore business. Through 2026, we remain focused on achieving first oil in Vietnam with key exploration wells planned in the Gulf, Vietnam, and Cote d'Ivoire and conducting additional geophysical studies. Overall, our payout to shareholders will increase during this time as we reach 3.0 of our capital allocation framework. Longer-term, we plan to reinvest approximately 45% of our cash flows, achieving an average production level of 210,000 to 220,000 equivalents per day with more than a 50% oil weighting. We're forecasting generating ample free cash flow to allocate towards additional debt reductions, further shareholder returns, accretive investments as well as supporting any exploration success. Additionally, as part of this plan, we remain committed to achieving metrics that are consistent with an investment-grade company. This year's plan has higher production levels in 2027 and beyond with significantly higher offshore production in those years compared to last. And further, we did lower our gas price in this plan, which you can see in the footnote of the slide. As we wrap things up here on Slide 27, looking back, we had a great year on safety and protecting our people. We continue achieving new company lows every year on emissions intensity. We made strides in executing our capital allocation framework and achieved our decade-low debt level on a net basis. We continue to reap the benefits of an oil-weighted high-margin asset base, and we grew our proved reserves. This team is excited to advance our field development project in Vietnam and began the procurement process last year. We look forward to potential upside in the area with our upcoming exploration wells, and we've also expanded our exploration portfolio with additional blocks in Cote d'Ivoire. We have a solid foundation to move forward. We'll continue building on our strong safety culture and target additional emissions intensity improvements. Shareholder returns remain at the forefront, and our debt reduction has only strengthened our balance sheet, making us more resistant to cyclical commodity prices. Our business, a large multi-basin portfolio generates peer-leading cash flow metrics that further support our shareholder returns while providing future optionality from our operations. Lastly, we look forward to maintaining our exploration capabilities to augment our portfolio in a measured approach. In closing, as always, I thank our incredible employees for their continued dedication and hard work supporting our company. That's the end of our prepared remarks today, we stand by for our calls, and we have a long list of calls here today. So here we go.

Thank you. Your first question is from Arun Jayaram from JPMorgan. Please ask your question.

Yes, good morning Roger and team.

Good morning, Arun.

Roger, I was wondering if you could shed some more light on your 2025 and 2026 kind of outlook. You've outlined a $1.1 billion average CapEx program from 2024 to 2026. And help us understand what type of spending projects you see in 2025 and 2026, which will impact the CapEx trajectory as well as how do you see spending trending in the LDV development, which looks like about $40 million this year but obviously probably going to rise as you get closer to first oil?

First on the question, thanks for that. We do have a plan this year we consider to be fairly consistent with latest prices and plans. We're going to be like a $1 billion CapEx company in those years. If you look at our CapEx from 2023 and 2024, it's very similar, and I suspect it remains so. We have an ample list of Gulf of Mexico, 2P projects; we have over 2 or 3 years of rig work there if we want it. We'll be keeping our Eagle Ford Shale at the same level and reaching up to the field in Montney. The LDV project is not super expensive for Murphy, probably around $300 million total, and it will be spread over 3 or 4 years very nicely. There will be no big slugs of CapEx there, and I would consider the CapEx in Vietnam to go up in 2025 and 2026, almost doubling or slightly more, possibly pulling back in some of our non-op projects at St. Malo as it gets going, and Terra Nova finishes their work. And as we get higher production in Montney going forward. This plan is very robust, and what's more robust about it in the past is we found more offshore projects to do with Vietnam. We have a much larger offshore business. If you compare plan to plan, our offshore production is about 10,000 barrels a day higher than in 2027. Our total production in 2028 is much higher than it was in the final plan, and our oil production is 5,000 or 6,000 barrels a day in 2028 compared to last year's plan. So this is a really good plan; we're going to accumulate between $5 billion and $6 billion of free cash flow from 2024 to 2028 million with the assets we own today, and we'll be able to return massive amounts to our shareholders through buybacks and have very large dividend levels because we will be purchasing so much stock. We're extremely well positioned with this plan; it's very much a consistent plan with inflation and the things happening and resurging just like you do every year. And it's in a really good shape, Arun.

Great, thanks Roger. I just wanted to follow up and see if you could provide an update on the life extension plan for Terra Nova, including how that has progressed and what ramp-up you anticipate, particularly regarding the net barrels.

I'm so pleased with that execution. I'm going to let Eric cover it for you.

Thanks, Roger. That's a great question. Regarding Terra Nova, as we previously mentioned, the life extension project wrapped up in the middle of last quarter, the fourth quarter of 2023. We averaged about 1,000 MBOE in production during that quarter. We anticipate that production will increase soon after they finish the final stages of additional compressor commissioning. In the first quarter, we expect production to rise to approximately 4,000 barrels per day. And on average for the quarter, as production ramps up, we expect it to be in the range of about 5,000 to 6,000 BOE per day net to Murphy.

Great. Thanks a lot gentlemen.

Thank you, Arun. Appreciate your call.

Thank you. The next question is from Neal Dingmann from Truist Securities. Please ask your question.

Hi morning. Thanks for the time. Roger, for you or Eric. Could you just talk a little more on color on Slide 18. I really think the upside from your Gulf obviously the Gulf offshore development seems to be quite material. And I'm just wondering, is the $300 million kind of change that you talked about recently, I guess, to be exact, is that for just the first 3 projects Marmalad, Khaleesi and Mormont? Maybe just talk about the timing behind. I know you have a timeline in here, but just maybe give a little more color on this, if you could, because it looks so sizable.

Thanks, Neal. The spending is across all of it, and I'll let Eric give you more detail.

Yes, sure. One of the things we're trying to highlight here is where we're spending money this year. Obviously, if you look at the slide, you see production coming online from new wells across the year in the Marmalad, Khaleesi, and Mormont fields. We're also highlighting that we're spending money in other fields, and it's basically long lead equipment that we're spending on in 2024 that will contribute to new volumes and new wells coming online in 2025, 2026, etcetera. And if we wanted to, we could make a table like this that would go on out to 2028, but we didn't do that. As Roger highlighted a few minutes ago, we expect relatively stable spending in our overall offshore business with all of these really awesome investment opportunities we have to continue to bring in more wells and conduct workovers, etcetera, in our offshore business and maintain those offshore volumes flat for the next several years with just the known stuff we have without exploration success anywhere.

Yes. Further on that, Neal, we have our Board meeting and we project our projects. These are well in excess of 100% rate of return. And later on in the slide deck, we talk about workovers, which are unfortunate; some of these wells had some mechanical problems after repair, the payout on these wells are 3-4 months. So everything we do offshore is 150%, 170%, 200% rate of return. So near infrastructure and unlike onshore, they're spending on things without necessarily drilling. We have to buy long-lead equipment items, production equipment, drilling equipment casing. So we're spending on things associated with all these developments. This is some of the best investments you can ever make in the oilfield today.

Neal, one thing you may want to have a look at Slide 39 in our presentation, where we try to highlight the depth of our offshore inventory. We don't disclose every single well by itself, but we do attempt to show you how strong and resilient they are. The majority of our offshore identified projects breakeven below $35 a barrel. So super robust, super strong, high return. They're well identified. These are known things in our portfolio that we're planning to bring forward over the next several years.

No, I'm glad you've got you all, but made return. It's certainly notable. And then just a quick follow-up on your onshore. It seems like, I think in the press release, you suggested about 1/4 of the Eagle Ford would be on field development. Is that normal? And can you just talk about what that will be directed for?

Yes. We use that term field development, Neal, to count things that are mostly associated with just bringing on new wells, but they're not specifically the drilling and completion cost. So if we have to build a pipeline to connect a new pad to an existing facility or if an existing facility requires some kind of upgrade to handle the new volume. So generally, it's just surface equipment that we're upgrading. It's also we continue to make improvements in our greenhouse gas and methane emissions, and we're spending a little bit of money there to drive those improvements in our Eagle Ford business. So it's mostly just bringing on new wells, the surface equipment related to it, but a few other enhancements that improve our operations and lower our downtime and help us with our free cash flows.

Thank you.

Thank you. Your next question is from Leo Mariani from Roth MKM. Please ask your question.

Good morning, Leo.

Good morning. I want to follow up on the Gulf of Mexico. You briefly mentioned this, Roger, but I'm not sure if I'm seeing this correctly. It appears there might be an unusually high number of well failures that have required workovers recently. I'd like to know if you attribute this to anything specific or if it's just a recent streak of bad luck. Also, regarding the Gulf, could you discuss M&A since we've seen asset trades lately and there may be more coming up?

Thanks, Leo. That's, you said it right. It's bad luck. It's nothing to do with anything. These are not related. There's a safety valve instrument in Dalmatian. This has been an occurrence that has happened in the Gulf to various operators through the years. You test the safety valve from a regulatory basis and the valve won't open back up for different kinds of reasons. Then we had to go do some studies about the metallurgy of the type of equipment we need. There's very little equipment on the ground by these large service equipment companies today. You have to procure things and get a rig; you can get rigs in the Gulf to do work. We've been able to do it. It's not that tight, we're able to do it. And then the well in Neidermeyer is a complex deep pressured well that had a communication issue between the tubing to the casing. We bought this well; we didn't complete this well, and it wouldn't have been the way we would have designed the well, we can say that, and we need to go fix the well. We have a rig there today to fix it. These things are unrelated. What's really happening to us here in this first quarter is some work that needs to be done that we had to procure and get the equipment to do with large downtime, for example, they're lifting up the famous subsea water injection equipment at St. Malo, which is a big deal for one of the greatest fields in the Gulf on the highest margin. Fields in the Gulf that have to be shut in and picked up. Delta House has some equipment that's being installed by another operator. So we have a lot of planned downtime that came in on top of some one-off workover leading to a low first quarter, and we haven't put a well online in onshore in quite a while. That's the way we run our business to have this incredible low free cash flow yield, and incredible leading net debt to EBITDA, with no bonds to be refinanced until 2027; the only energy company in that situation. So all that's set up to provide all that safety for our shareholders, and we're returning money to shareholders. To wrap all this up, some poor luck, things happened with some downtime. As to M&A, thanks for asking that question. We are a company that prides ourselves in very successful M&A, over $8 billion of M&A in the decade here. We have an incredible team, a senior team, and we have a proprietary process to look at things on a certain basis. The recent large deal is something that didn't fit the criteria of us. We've known about the deal for a long time. If you back up to 30,000 feet, what's the difference is the debt-to-EBITDA level of the outcome of that deal versus us striving to be one times debt-to-EBITDA at $45 oil, not 1.6 net EBITDA at $75 oil. We're in a different total world. We have all the assets we need and we're striving to protect our shareholders through large returns and cycle pricing and with this incredible balance sheet. That's kind of how we think it. There are plenty of opportunities. We look at them all the time, and we're very proud of our screening and our process that we have that's led to great success on the M&A front here. One of our best things that we do actually. Thank you, Leo, for supporting us and calling in today.

Yes, I appreciate that, Roger here. Maybe just a quick follow-up on the Eagle Ford here. So it seems like you guys are somewhat electing to turn in quite a bit fewer operated wells in 2024 versus what you did in 2023, and it seems like that's really kind of leading to production ticking lower. Can you maybe just kind of talk through that a little bit? I know you're bringing on a slug of wells kind of early in 2025, but just a little surprised to kind of maybe see some of the timing with a lot of fewer turning lines this year?

Yes. Thanks, Leo. This is Eric. I'll just give you a bit of my thoughts on that. In the Eagle Ford, we are expecting 30,000 barrels a day in 2024, down about 3,000 barrels a day from 2023. We're pulling back our capital program there just a little bit. Some of that's driven by just the timing around when we're bringing on the wells. We're bringing on the average new well a little bit later this year than before. Capital decisions we made in 2023 had us entering the year without any wells to complete early. So we're drilling wells in the Eagle Ford before we can complete them. And then we're happy that within our overall framework, direct some capital investment to Vietnam for future long-term growth there without changing our total capital level, but replacing a little bit of Eagle Ford spending with Vietnam spending and set us up for a nice long plateau out there in Vietnam. I expect that in 2025, you'll probably see a little bit higher level. Our exit rate in Eagle Ford at the end of 2024 ought to be quite a bit higher than we saw in 2023, due to the timing of the new well delivery. You should see us, as we've said for several years now, manage Eagle Ford in a 30,000 to 35,000 barrel a day range with pretty consistent CapEx. We are really excited about this new rig we picked up; it's just flying through the first lateral, and happy to see that. Hopefully, we can see additional operational improvements and capital efficiencies there as we progress through the year.

Thank you. That’s very clear. Appreciate it.

Thank you. Your next question is from Paul Cheng from Scotia Bank. Please ask your question.

Good morning, everyone. I have two quick questions. First, for Tom, can you clarify how you calculate the cash payout? Is it based on your full-year estimate, or do you approach it on a quarterly basis? The second question pertains to your last quarter presentation. You mentioned an expected budget of around $900 million for 2023 to 2025, but now it's $1.1 billion for 2024 to 2026. While that's only a one-year adjustment, the production outlook seems similar. You mentioned focusing on Vietnam with about $300 million—are there other factors contributing to this budget increase that we should consider?

Thank you, Paul. I’ll discuss our execution of the framework, which we are quite enthusiastic about as we transition into 2.0 and are more than halfway through it. We consider this in relation to meeting our annual debt targets. As we've indicated, our capital expenditures are front loaded, and we expect to see a greater portion of our adjusted free cash flow later in the year. We assess it on a quarterly basis to identify opportunities for executing aspects of our framework, but ultimately, we view it annually to ensure alignment with our commitment to shareholder returns.

So Tom, if I’ve got it correctly, it means that in any particular quarter, you may buy back more or less than the 25% that the current indicator would suggest, right?

That's right. Yes, you may notice some fluctuations as we aim to achieve that annual target.

We are willing to purchase stock on our revolver if we find ourselves out of sync with the group, as our company is solid and generates strong cash returns. Regarding our long-range plans, I appreciate the question. On the capital expenditure side, yes, it’s increased. Last year, we didn’t allocate enough for exploration, and to enhance our exploration business, we need a portfolio that balances lower and higher risk throughout the year and also in terms of cost. The big wells in the Gulf are quite costly, while other regions have more affordable options. This year, our exploration portfolio carries a much lower risk. We have increased our exploration budget by over $40 million annually over the last three years. In terms of cash flow, we've reduced our gas prices in the plan, which is noted, and we’re also executing a $300 million project in Vietnam focused on cost evaluation. Regarding production, it's clear that Terra Nova was expected to be operational last March, but that hasn’t happened, so we are starting from scratch to ramp up. St. Malo has produced an impressive production well and continues to show increasing oil in place, being one of our top assets globally, but the project is significantly behind schedule. The capital expenditure has been utilized, but production has been postponed, and they are only now installing the water injection equipment. When all of this is considered, we are expecting similar production results, particularly for oil, compared to last year, albeit with increased spending. Our projections for 2027, 2028, and 2029 are stronger than before, leading to a significant amount of free cash flow that is approaching our previous market cap. As we move forward, each year the plan improves, although we encounter changes in phasing and manage various non-operated large projects like Terra Nova, St. Malo, and Lucius with Occidental. The situation remains unchanged, and we have put everything back together. Ultimately, production is the result, and our primary focus is on generating free cash flow and returning value to shareholders. We have a strong capacity for free cash flow that is quite similar to last year's plan. Our attention remains on that rather than minor fluctuations in production, which we consider an outcome rather than an input. My treasurer highlighted this point recently, and that summarizes our approach.

Thank you.

Appreciate all the years. Thank you.

Thank you. Your next question is from Charles Meade from Johnson Rice. Please ask your question.

Good morning, Charles.

Good morning Roger, thank you to you and your team. I appreciate you providing the $300 million debt reduction target for 2024. We can calculate how that will lead to Murphy 3.0, but you could begin that process today with the cash available on your balance sheet. Can you share your thoughts on the timing for achieving that $300 million in debt reduction?

It will be later this year and throughout the year. But I'll let Tom walk you through that, Charles, a little bit here.

Yes, Charles, thanks for that question. As Roger said, we'll be planning to utilize more of our adjusted free cash flow towards the second half of the year. We do have a little over $300 million of cash coming into the year. That's a balance that we try to hold just to manage our business and some of our operational needs and our international and domestic activities. So we like to try to keep that cash balance around $300 million to $350 million for those needs. As you may have noticed, coming into 2023 last year, we had a little over $400 million of cash, and we did use some of that towards our framework as we got into the year. But as I mentioned to Paul's question, we try to manage this on an annual basis, this framework. I think we'll see more of that happening for the second half of the year.

That is helpful, Tom. Roger, I wanted to ask about the two Gulf of Mexico prospects you added, Orange and Ocotillo. If I'm calculating correctly, after accounting for the $120 million of net mean from the Vietnam prospects, it seems these two Gulf of Mexico prospects are valued between $20 million and $30 million gross. Could you confirm my calculations? Also, can you discuss the timing of these prospects and what the development timeline would look like if they are successful?

I think they are somewhat larger than that, likely in the 40s range. There's a longer story behind this. We just drilled a well that we previously identified as disappointing. However, our team is performing exceptionally well, and we have a strong enhanced team in place. People are showing interest in trading and becoming part of our business. When we drilled the Oso well, it facilitated some collaboration with Occidental, also known as OXY. This allowed us access to two of their prospects in exchange for them engaging with ours. Additionally, we have a favorable acreage position near Delta House. We recently executed a significant land trade, attracting interest in our acreage, and we are developing a portfolio of other wells. We are leveraging our prospects to access additional opportunities, indicating that others recognize the quality of our prospects. In fact, we are successfully trading and building a solid portfolio. Chris Olson, our exploration leader, along with our land team, is doing an excellent job coordinating everything. I spoke with Paul Cheng earlier about the risks associated with our program. Occasionally, we face higher risk programs year to year; this year's program is comparatively lower risk. These involve amplitude type plays situated close to one of Oxy's very successful fields, allowing for tight connections to their operations. This strategy is distinct from our past drilling endeavors, including Oso. We are looking at lower risk and cost this year, supported by strong partnerships and advantageous acreage arrangements. In Vietnam, we are re-entering an area that has been on hold for us. That's a quick overview of our current activities.

That’s helpful detail. Thank you, Roger.

Thank you, appreciate it.

Thank you. Your next question is from Tim Rezvan from KeyBanc Capital Mortgage. Please ask your question.

Good morning, Tim. How’re you doing?

I am well. Thanks for taking my question. I wanted to dig back into the Eagle Ford. You have a clear, as a company, a long-term growth and income approach; there's inherent variability in your Gulf business. So I'm trying to understand why with the uplift in productivity from new completions, why not run more of a continuous program in the Eagle Ford? It's hard to think that that wouldn't compete for capital, especially given the comments you've given about the high-spec rigs. So just curious on that.

We focus on our offshore business typically first because these are infrastructures that need to be used. And on a pure return basis, the returns are better. But on a risk basis, it's different and the outcomes. It's not quite as volatile as you say; we've had three really strong years of work in the Gulf made enormous billions and billions of free cash flow in our Gulf business. So we just want to hold it in here and use it later if our Gulf business, our offshore business declines. It's a big advantage. We're showing a plan to our Board to produce past 2050 with assets that we own without any M&A or any exploration success. So we're a little different animal there. And we're trying to get our balance sheet in great shape. But I'll let Eric give you a little better color than that on this choice of capital allocation.

Yes, I think Roger, you're right on. I mean the returns for offshore projects are typically higher than our Eagle Ford. And we like our Eagle Ford; we have great returns. We have highlighted in our slides here how many years of great inventory we have. And we do really like the optionality we have to maintain the scale of our business and the oily scale of our business for many decades by investing in the Eagle Ford in the future. What Roger briefly touched on was that in the offshore space, it's common that if you do not pursue an opportunity, the infrastructure where you can take that new well as a subsea tieback to a facility, the facility has a defined life. It won't be there forever. And so you like the returns, and you want to use it or lose it. In the Eagle Ford, that well is going to be waiting for us whenever we want it. So we like the flexibility that it provides for us. The other thing just to highlight that we have reduced our capital program in the Eagle Ford over the last few years and have generated strong free cash flows, which we've used to delever and return more money to shareholders, which we think is valued by our shareholders.

We have the Eagle Ford for the long-term, and we have it when we need it. We can change capital allocation on a dime here in 30 minutes. We can change cap allocation. So we're proud to have it. I think it's going to become more and more valuable. And I think all of our onshore assets will become more and more valuable with the scarcity of the peers in that group that only do that business decline over the next decade. There are very valuable assets in both Canada and the Eagle Ford.

I appreciate the information on that. For my follow-up, I would like to shift the focus to Vietnam. You're planning to allocate $40 million for exploration wells this year, and you've recorded 13 million barrels of proved undeveloped reserves. Can you explain the assumptions that went into those reserve bookings? Is that solely based on that? I'm trying to understand the potential upside from the exploration wells and how that has affected the reserves you've recorded, along with an overview of the other developments in that area.

Yes, thank you for the question. I want to give you a brief overview of our business in Vietnam and our perspective on it. We are quite enthusiastic about the Lac Da Vang project we are initiating. This year, we plan to invest $40 million in capital expenditures for the development project. As previously mentioned, we expect this amount to be around double for 2025 and 2026, with first oil expected in 2026. This project has the potential to yield 10,000 to 15,000 barrels net to us, but we aim to expand our operations there and take advantage of excellent exploration opportunities close to our existing infrastructure for Lac Da Vang. Our costs for exploration wells are slightly lower than you indicated; our exploration well expenses are in the range of $30 million to $35 million net. The prospects we have are significant and promising, particularly in the Cuu Long Basin, which is known for its high oil yield in Vietnam. We have not encountered a dry hole; the area is rich in oil. There might be some developmental synergies since one of the prospects in Block 15-105 is very near to our Lac Da Vang development. If successful, we can bring that field online more quickly, enhancing our profitability and free cash flow. The prospect in Block 15-2 is substantial for us, with the potential for our overall operations in Vietnam to reach 30,000 to 40,000 barrels of oil equivalent per day, which would significantly boost our business and generate considerable free cash flow. We are very excited about the prospects and look forward to updating you on the results of our Vietnam wells in the latter half of 2024.

Thank you very much.

Thank you. Appreciate it.

Thank you. Your next question is from Roger Read from Wells Fargo. Please ask your question.

Good morning. As we begin the E&P earnings season, I have a question regarding capital allocation. It's been touched on a bit, but considering you are an exploration company that has remained committed to exploration through various environments, including your recent move with Zephyrus to acquire an existing discovery, I want to know how you evaluate your options. Specifically, when looking at acquisitions, exploration, and share buybacks, how do these strategies fit into your overall evaluation? Which one seems most appealing, and how do you see these competing strategies evolving over the next five years as you plan your long-term program?

Thank you for the question, Roger. I appreciate it. We believe that an E&P company needs to maintain some level of exploration spending; otherwise, it risks becoming stagnant. We have increased our exploration budget to enhance our portfolio's long-term value. When I think about sustainability, I consider our strong environmental attributes. We have consistently ranked highly in sustainability metrics, and to me, true sustainability means having a robust asset base that endures for decades. Our Board has even reviewed a production forecast extending beyond 2050 with our current assets. We aim to complement these assets with more oil-focused exploration rather than solely relying on our significant gas reserves in the Montney. We believe that maintaining a capital expenditure level of 8% to 10% allows us to create a long-term, lower-risk exploration portfolio that balances our risk profile. Our stock buyback program is also an effective capital allocation strategy, and we are committed to it. Our execution in our first year was very close to our targets. We're focused on free cash flow and project that we will generate over $1 billion annually from 2024 to 2029 with our existing assets. This gives us the capacity for additional exploration while ensuring the sustainability of our onshore assets over the long term. Murphy is not going out of business; we are maintaining our operations through careful capital allocation. Additionally, we can repurchase a significant portion of our shares each year, which is beneficial since we haven't issued equity since going public in the 1950s. Our shareholder value remains strong, with a consistent dividend and significantly reduced net debt compared to 2016. We intend to preserve our dividend and prepare our balance sheet for potential M&A opportunities. Speaking of M&A in the Gulf, we've identified promising prospects and are continuously seeking opportunities to enhance our infrastructure. As a leading operator in the Gulf with an excellent uptime record, many want to collaborate with us, and we are well-positioned to evaluate every opportunity that comes our way.

I appreciate that. I'll leave it there given the busy morning here. Thank you, Roger.

Thank you, appreciate it. See you soon.

Thank you. Your next question is from Neil Mehta from Goldman Sachs. Please ask your question.

Good morning Roger. I'll just ask one because I know we're over time, which is just...

Neil, you’re Goldman Sachs. Can you ask anything you want as long as you want.

Thank you. It was great to have you in Miami. My only question is about the balance sheet; you've done an excellent job reducing leverage. You are one level below investment grade. When you discuss this with Moody's, S&P, and Fitch, what do they say needs to be done to achieve investment grade? Is this a priority for you?

I think I'm going to let Tom answer that. The priority to me is we meet with our Board as we have a red light, green light, yellow on everything that Moody's requires. We focus on are we meeting investment-grade criteria. That's our first step. I'm focused on free cash flow every day, all day, and I'll let Tom talk to you about Moody's here. He's an expert on that.

Thanks, Roger. Yes, Neil, the way we're thinking about it, we really can't control how these rating agencies might change what's most important, what's our priority. We've been investment grade before; we operate like an investment-grade company in terms of our decision-making. We are getting back to our conservative balance sheet, which we've had a long history of having a conservative balance sheet. And so that's how we intend to operate. When we talk to them, we tick a lot of their boxes. I think the theme that we're seeing by some other operators and some other activity in the industry is around scale. We don't think that that's something that is going to push us into doing anything. We think we're at the right side, execute most beneficially for our shareholders. While we are one notch below, it's not limiting our ability to execute our plan. We think we have ample access to capital to continue to provide the types of returns that our shareholders are expecting.

Alright guys, thanks so much.

Thank you, Neil. Thanks for hanging in to the end, and we'll be seeing you soon. Appreciate it. Okay. That's the end of our call today. We had a lot of robust calls for many of our long-term analysts. We appreciate that. We're first out in E&P today. We're glad to have it behind us, and we wish all of our peers as well as they go through it going forward. We're very well positioned, very safe balance sheet, ever-increasing dividend, and focus on our shareholders. I'm very proud of the company; very proud of my team, very proud of what we have going on here. I appreciate everyone's focus this morning. It's been a long call. Thanks so much. See you soon. Goodbye.

Thank you. Ladies and gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect.