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Murphy Oil Corporation misses on earnings expectations. Reported EPS is $0.9 EPS, expectations were $1.03. Murphy Oil Corporation isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Good morning, ladies and gentlemen. And welcome to the Murphy Oil Corporation Fourth Quarter 2023 Earnings Conference Call and Webcast. [Operator Instructions] I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Kelly Whitley: 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 10-K on file with SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger Jenkins.

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 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 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’re continuing delivering shareholder returns and reducing debt levels. On Slide three, Murphy’s production averaged 185,000 equivalents 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 nat gas. This led Murphy generating $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 NCI. On Slide four, 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 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 am 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, must also consider that our strong reserve outcome is based on oil price that was $15 per barrel lower than 2022. Further, 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?

Thomas Mireles: 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. And 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 is a focus 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. And with that, I’ll turn it back over to Roger.

Roger Jenkins: Thank you, Tom. Let’s look now to the quarter results and our onshore assets we produced and combined 100,000 barrels equivalent today with 30% liquids weighting in quarter 4 and Eagle Ford Shale we produced 31,000 equivalents per day with 86% liquids. We brought on 3 non-operated wells in Tilden as 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 at 82% oil.

The Gulf of Mexico production totaled 81,000 equivalents per day. We brought online 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. And 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 gain 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 6000 per day associated with the wells currently off-line that are scheduled for work overs and will return to production in the first half of the year.

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 a damaged subsea equipment in the Mormont field in the Gulf of Mexico. For the full year 2024, we forecast 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?

Eric Hambly: 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 for 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 the progressing of 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 a 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.

Roger Jenkins: Thank you, Eric. As to exploration, our total 24 exploration plan of $120 million support 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, 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’re 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 [indiscernible] exploration well in Block 15-1 was flood in the fourth quarter of 2024. This well is just to the southwest of our Lac Da Vang field development and will target a main upward gross resource potential of $65 million to $135 million equivalent. Overall, these two exciting prospects gained further advantage by 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.

As well 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 and resulted in a 0.7x debt to trailing 12-month EBITDA based on third quarter results. We’ve been able to accomplish this delevering 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 maintaining 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 in 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 to approximately 95,000 of 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 reached 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 and 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 be seen in the footnote of the slide. As we wrap things up here on Slide 27, as we look 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 a potential upside in the area with our upcoming exploration wells. And also expanded — 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, and it made us more resistant cyclical commodity prices. Our business, a large multi-basin portfolio generates peer-leading cash flow metrics, but 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.

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Operator: Thank you.[Operator Instructions] Your first question is from Arun Jayaram from JPMorgan. Please ask your question.

Arun Jayaram: Yes, good morning Roger and team.

Roger Jenkins: Good morning, Arun.

Arun Jayaram: 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, it looks like about $40 million this year, but obviously probably going to rise as you get closer to first oil?

Roger Jenkins: 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 $1 billion CapEx Company in those years. And if you look at our CapEx from 2023, 2024, it’s very similar, and I suspect it remains so. We have an ample list of Gulf of Mexico, 2P projects we call them the last — we have over 2 or 3 years of rig work there if we want it. We’ll be keeping our Eagle Ford Shale in that same level and reaching up to the field our plant in the 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 and pull back in some of our non-op projects at St. Malo gets going. Terra Nova finally finishes their work. And that we get higher production in Montney to go forward. This plan is a very robust plan and what’s more robust about it in the past as we have found more offshore projects to do with Vietnam. We have a much more — much bigger offshore business. If you compare plan to plan, our offshore production is some 10,000 barrels a day higher than 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 it will be purchasing so much stock. And we’re extremely well positioned with this plan. It’s very much a consistent plan with inflation and things happening and resurging a plan like you do every year. And it’s in a really good shape, Arun.

Arun Jayaram: Great, thanks Roger. And I just had a follow-up. I was wondering if you could give us an update on the life extension plan, how that went to Terra Nova, and just kind of the ramp that you expect maybe some details on how you expect that ramp to play out kind of net to you — net barrels?

Roger Jenkins: I’m so super pleased with that execution. I’m going to let Eric cover it for you.

Eric Hambly: Thanks, Roger. That’s a great question. On Terra Nova, as we highlighted before, the life extension project was completed at the end of — created completed, sorry, in the middle of last quarter, fourth quarter of 2023. And we produced about 1,000 MBOE [ph] average in the quarter. We expect that the production will ramp up here pretty soon after they complete sort of the final stages of additional compressor commissioning. And in the first quarter, we expected to come up to around 4,000 barrels a day. And then on an average basis because it’s ramping through the quarter. And then for the last three quarters of the year, we expect production to be in the range or be around 5.5000 BOE per day net to Murphy.

Arun Jayaram: Great. Thanks a lot gentlemen.

Roger Jenkins: Thank you Arun. Appreciate your call.

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

Neal Dingmann: 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 seem to be quite material. And I’m just wondering, is the 300 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 time line in here, but just maybe give a little more color on this, if you could because it looks so sizable.

Roger Jenkins: Thanks, Neal. They’re spending across all of it, and I’ll let Eric give you more detail.

Eric Hambly: Yes, sure. So 1 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 Mormont fields. We are 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, 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. So 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 do 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 an exploration success anywhere.

Roger Jenkins: 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 fix, the payout on these wells are 3, 4 months. So everything we do offshore 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. They’re spending on things associated with all these developments. This is some of the best investment you can ever make in the oilfield today.

Eric Hambly: 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. So 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.

Neal Dingmann: No, I’m glad you’ve got you all, [indiscernible], 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?

Eric Hambly: 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.

Neal Dingmann: Thank you.

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

Roger Jenkins: Good morning, Leo.

Leo Mariani: Hey good morning. I want to kind of quickly follow up on the Gulf of Mexico. You kind of briefly mentioned this, Roger, but I don’t know if I’m looking at this right, but it seems like maybe there’s been kind of a — I don’t know, an unusually kind of high number of sort of well failures that have required workover of late — just wanted to get a sense if you guys are attributing that to anything in particular out there, maybe this is just kind of a recent bad streak of luck and just in the Gulf, I was hoping you could also maybe talk about M&A as I guess we’ve seen an asset trade lately and perhaps there’ll be others coming out of the Gulf?

Roger Jenkins: 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 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, procure 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.

It looks like between the tubing to the casing. We bought this well. We didn’t complete this well. 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, and we have a rig there today to fix it. These things are unrelated. And 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 has 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, incredible leading net debt to EBITDA, 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. So 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. And I think 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. So 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. So that’s kind of how we think it. So for us to do M&A, it’s a certain criteria of the age of the assets and the returns that we like that fit in with our framework, and we have — that’s how we judge that. And that’s the answer on that.

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 a great success on M&A front here. One of our best things that we do actually. So thank you, Leo, for supporting us and calling in today.

Leo Mariani: 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 line 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?

Eric Hambly: Yes. Thanks, Leo. This is Eric. I’ll just give you a little 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. And 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 we’re able to, within our overall framework, direct some capital investment to Vietnam for future long-term overly growth there with not changing our total capital level, but displace a little bit of Eagle Ford spending for Vietnam spending and set us up for a nice long plateau out there in Vietnam.

And I expect in 2025, you 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. And you ought to see us, as we’ve said for several years now, managed 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. And hopefully, we can see additional operational improvements and capital efficiencies there as we progress through the year.

Leo Mariani: Thank you. That’s very clear. Appreciate it.

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

Paul Cheng: Hey good morning guys. Two quick ones. Maybe the first one is for Tom, just to maybe remind us. On the cash payout, when you calculate it, is it your estimate for the full year and then you provided or that you just do it quarter-by-quarter. The second question, I was looking at your last quarter presentation. You are looking for 2023 to 2025 at about $900 million now that you say in 2024 to 2026 is $1.1 million. Now obviously, that’s a 1-year change, but I don’t think that really make the difference. Your production outlook is largely about the same. So — and you just mentioned that Vietnam is really [indiscernible] to you, only about 300. So is there any other areas that we should be aware why that the increase in budget?

Thomas Mireles: Okay. Thanks, Paul. I’ll talk about the first one on how we’re executing our framework, which we’re really pretty excited about how we’ve moved into 2.0, and we’re more than halfway through it. We do think about this in terms of hitting our annual targets here for our debt target. So quarter-by-quarter, as we’ve disclosed, our CapEx is front loaded. So we’re not going to — we’ll see more of our adjusted free cash flow towards the back end of the year. But we do monitor it quarter-by-quarter to see if there’s an opportunity to do something to execute part of our framework. But really, it is something that we’re looking at on an annual basis to make sure we try to stay in line with our commitment to returns to shareholders.

Paul Cheng: So Tom, if I get 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?

Thomas Mireles: That’s right. Yes. You’ll see some — you may see some fluctuations there and try to hit that annual number for us.

Roger Jenkins: We’re not afraid, Paul, to buy stock on our revolver if we get separated from the group or the pack here because our company is a very solid company with incredible cash returns. Let me take a stab at the LRP — long-range plans, what we call it. Thanks for that question, fair question. On the CapEx side, yes, it’s higher. During this period, last year, we didn’t have enough for exploration and to improve our exploration business, we need to build a portfolio that allows us a mixture of lower risk and higher risk throughout the year and also lower risk and high risk as to cost. These big 33,000 foot wells in the Gulf are very expensive. In other parts of the world, they’re much less expensive. And on the risk side.

We have a much lower risk exploration portfolio this year. So we’ve added over $40 million a year during this 3-year period for exploration. On the cash flow side, we’ve lowered our gas prices in the plan that’s footnoted and we’re also executing a $300 million project in Vietnam. And it’s just a relook at the cost. And if you look at production, let’s just be honest, Terra Nova is supposed to be up and running last March, it’s not. And then you have to start off now and ramp that up. St. Malo incredible field just drilled an incredible production well there. The oil in place at St. Malo continues to increase, probably one of the top assets in the world, but the project is very late. So the CapEx has been spent. The production has been delayed.

They’re just now putting on the water injection equipment. So when you add all this up, you have a similar production result, but very, very same on oil. Very similar on the oil side to last year and more spending. But our 2027, 2028, 2029 is more robust and better than it was and leading to still a large amount of free cash flow approaching our yesterday market cap, in fact. And so there, we have it on that, Paul. But just every year, the plan gets better, things happen, things change in phasing. We deal with a lot of non-op big projects like Terra Nova and St. Malo and Lucius with Occidental. And nothing’s changed. We added up, put it back together. But at the end of the day, production is an outcome, and we’re focusing on free cash flow and returning to shareholders and we have an outstanding ability to have free cash flow very similar to last year’s plan.

So we focus on that, not the little ins and outs on small variances in production. That’s an outcome for us, not an input. So my treasurer tell me that yesterday, great line. So that’s what we’re doing on that, Paul.

Paul Cheng: Thank you.

Roger Jenkins: Appreciate all the years. Thank you.

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

Roger Jenkins: Good morning, Charles.

Charles Meade: Good morning Roger, to you and your team. Thank you. Roger, I wanted to ask — thanks for giving us that $300 million debt reduction target for 2024 and we can do that math that will get you to Murphy 3.0, but you could start on that today with just the cash on your balance sheet. So can you — can you give us some insight on how you’re thinking about the timing of that $300 million in debt reduction?

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

Thomas Mireles: 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, 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. And I think we’ll see more of that happening for the second half of the year.

Charles Meade: That is helpful, Tom. And then Roger, I wanted to ask about these two Gulf of Mexico prospects that you added Orange [ph] I think — I didn’t — I don’t remember the other. Ocotillo — if I’m doing the math right, it looks to me after you mentioned the $120 million of net mean after taking away the Vietnam prospects. It looks like these two Gulf of Mexico prospects are in the range of $20 million to $30 million gross. And I wondered if that’s the — if I’m doing the math right there. And if you could just talk a little bit about the timing of those prospects and what they look like and what the development time line would be if you get on that success lag?

Roger Jenkins: I think they’re a little bigger than that. I believe they’re in the 40s range. A story there. It’s a long story. We just drilled this well so. It’s a disappointing well that we disclosed earlier. But our team is doing a great job. We have a great team. We have a new enhanced team here, and people want to trade and be in our business. So when we drilled Oso for people to come into that well, Occidental, a close relationship with them, OXY. We were able to get into two of their prospects for them joining ours. We also have a very nice acreage position near Delta House. We recently did a large land trade where people want to come into our acreage, and we build into a portfolio of other wells. So we’re using our prospects to gain entry into other prospects, meaning people believe our prospects are good.

As a matter of fact, we’re doing extremely well in trading in and out and building a really nice portfolio, Chris Olson, our exploration leader, and our land team is doing a great job pulling all that together for us. These are — again, I spoke to Paul Cheng a few minutes ago about the risk of the program on occasion, you end up with a higher risk program year-to-year, I consider this year lower risk. These are amplitude type plays near one of Oxy’s very successful fields can be tied back very closely to where they work. These would be near-field tieback, totally different from Oso, totally different from other things that we drilled in the past. So this year, we have some lower risk, lower cost not its deep and tough wells, if you will, and some really nice wells in Vietnam that we’ve been on the sidelines in Vietnam for a long time until we made plans with our field development plan with that host government, now the host government is very interested and us moving forward, that’s going extremely well.

So they’re smaller wells, they’re lower risk. With a great partner, they come from acreage situations that we put together. And in Vietnam, we’re back in an area that’s been on hold for us. So that’s kind of a fast wrap-up of what we got going on there, Charles.

Charles Meade: That’s helpful detail. Thank you Roger.

Roger Jenkins: Thank you, appreciate it.

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

Roger Jenkins: Good morning, Tim. How’re doing?

Timothy Rezvan: 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.

Roger Jenkins: 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.

Eric Hambly: 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. And 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.

Roger Jenkins: We have the Eagle Ford for long-term, and we have it when we need it. We can change capital allocation on the 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’s very valuable assets in both Canada and the Eagle Ford.

Timothy Rezvan: Okay. I appreciate the color on that. On my follow-up, if I could pivot to Vietnam. You’re allocating $40 million to the exploration wells this year. You did book the 13 million barrels of pud reserves. Can you talk about the assumptions behind those reserve bookings? Is that strictly based on that? I’m just trying to understand kind of what the upside could be from the exploration wells and how that impacted the reserves you booked and just kind of overview on how that — the other play there?

Eric Hambly: Yes. Thanks for the question. I’ll just give you a quick run through of our overall Vietnam business and how we think about it. We really like this Lac Da Vang project that we’re working on now. Just getting started. We’re going to spend $40 million net to us on the CapEx in development project for this year. And as Roger highlighted earlier, there’ll probably be somewhat close to double that in 2025 and 2026, first oil in 2026. It’s a nice development, 10,000 to 15,000 barrels net to us, but we would like to have a bigger business that’s more material there, and we’re fortunate to have excellent exploration prospects very close to our existing infrastructure that we’re building out for Lac Da Vang. We’re spending a little bit less on the exploration wells than you mentioned.

I think you might have switched the development cost with exploration costs. So our exploration well cost is kind of in the $30 million to $35 million net range, and they’re very sizable, very exciting prospects in the Cuu Long Basin. We haven’t drilled a dry hole. It’s very oily. It provides almost all the oil in Vietnam. And there may be some development synergies. One of the fields — one of the prospects for drilling in the Block 15105 is particularly close to our LDV development. So on success, the ability to bring that field online faster than otherwise is an advantage from making money perspective from a free cash flow generating perspective. And then the prospect in the 15.2 is very sizable, very material for us. And could have the potential that our overall business in Vietnam could be a 30,000 to 40,000 net BOE a day business, which will be a really great piece of business for us there and generate tremendous amounts of free cash flow going forward.

So we’re super excited about it and look forward to giving you an update on the results of those Vietnam wells in the second half of 2024.

Timothy Rezvan: Thank you very much.

Roger Jenkins: Thank you. Appreciate it.

Operator: Thank you.[Operator Instructions] Your next question is from Roger Read from Wells Fargo. Please ask your question.

Roger Jenkins: Good morning, Roger. Good to hear from you.

Roger Read: Thanks. Good to hear you all. Getting us started here with the E&P earnings season. Just — I think my question comes at you from kind of the capital allocation. It’s been danced around a little bit. But looking at the fact you’re an exploration company, you’ve stuck with exploration through all the environments, you are even in the case, I think it was Zephyrus buying into an existing discovery. So you step back, Roger, you look at your options here, acquisition, exploration, buyback your shares, how does all of that fit in when you’re doing the true evaluation here? Like which one looks the best, which one — how do you think about them competing over the course of, say, the next five years as you look out at your long-range program?

Roger Jenkins: Thanks for that question, Roger. I appreciate that. The way we think about it is you have to have some level of exploration spending if you’re an E&P company or if not, you’re just a peak company. And so we have raised that because we need to build a better portfolio for the long-term value of the company. When I think of sustainability, we have all the attributes of all the ESG sustainability. We ranked top in ISS, ranked number 1 by every ranker, lowest emissions, incredible focus and all that. But to me, sustainability is having that in an asset base that last for decades. As I mentioned on a prior call, our Board has seen a production forecast past 2050 with the assets that we own today. So we like to augment those assets with more oil-weighted exploration and not become a totally gas company because we have tees and tees of gas in the Montney.

So we feel that at a 10% level of CapEx, 8% to 10% level of CapEx, we can build a long-term lower risk exploration portfolio that doesn’t have — that evens out the risk profile for the year, which we just talked about here with the previous caller. So we have that. Our buyback of stock is very, very good allocation of capital as well. And we disclosed the framework that we’re quite serious about. And if you look at the actual data, it would within 1% or 2% of that execution on our first year. So we measure all that through and focus on free cash flow. So what we want to build and what we have between now and 2028 is — I’m looking at all the free cash flow every year from 2024 to 2029. We make $1 billion a year or more every year of free cash flow.

So we’re doing that with the assets we own then we can augment that with exploration last longer and longer and longer at that same oil weighting and still have all of our onshore assets there to back us up to last for decades and decades. We’re not going out of business at Murphy. We’re sustaining our company through the capital allocation process that we have. And along the way, we’re going to be able to buy a lot of stock. One of the key advantages of Murphy because we never issued equity since we went public in the 50s, we only have 154 million shares. So we can buy 5% or 6% of the company every year without any problem at all. So just a different animal. I’ll show all this business today about our incredible balance sheet and our shareholders today have $1.20 a share dividend, the same as 2016 with way less net debt.

So we’re protected not to lower our dividend anymore. That’s what we wanted to do, and we want to have the balance sheet in another cycle to pounce on M&A. And that’s how we look at it. From an M&A perspective in the Gulf, we did buy a very nice situation. It’s getting better, we believe, on subsurface. We occasionally look at prospects near our infrastructure, we could then flow those barrels to us. We don’t have that deal done. We’ll need to compete, but we’re the top operator in the Gulf, high-uptime in the Gulf, highest record in the Gulf. People want to flow to us. And that’s an opportunity for us to make an incredible high rate of return. And people want us in their project, even though we’re not opt to help along the way with our expertise.

So things come to us. We get to look at every deal and that we’re extremely well positioned, Roger, to be honest with you.

Roger Read: I appreciate that. I’ll leave it there given the busy morning here. Thank you Roger.

Roger Jenkins: Thank you, appreciate. See you soon.

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

Neil Mehta: Good morning Roger. I’ll just ask 1 because I know we’re over time, which is just…

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

Neil Mehta: Thank you. It was great to have you in Miami. My only question for you is just the balance sheet, you’ve done a terrific job getting leverage down here. You are one notch — I believe below investment grade. When you’re having conversations with Moody’s, S&P and Fitch, what’s their message about what needs to be done to get you over the finish line to get to that investment grade? And is that a priority? Is that important for you?

Roger Jenkins: 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 expert on that.

Thomas Mireles: 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.

And so while we are one notch below, it’s not limiting our ability to execute our plan. And we think we have ample access to capital to continue to provide the types of returns that our shareholders are expecting.

Neil Mehta: Alright guys, thanks so much.

Roger Jenkins: Thank you, Neil. Thanks for hanging in to the end, and we’ll be seeing you soon. Appreciate it.

Roger Jenkins: 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.

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