Murphy Oil Corporation

focused on debt reduction since 2020. Between August 2020 and August 2022, excuse me, we reduced total debt by $730 million. Since announcing the framework in August of 22, we've consistently executed a combination of debt reduction, share repurchases, and dividend increases. And since total year 2020, we've reduced debt by $1.7 billion. We purchased a total of $200 million of stock or 4.7 million shares at an average price of $42.68 a share and raised our quarterly dividend 140%. In the first quarter of 2024 specifically, we generate sufficient adjusted cashflow to allow us to purchase 50 million of stock and capitalize on stock price dislocation to oil prices. For 2024, we solidly on track to achieve our $300 million debt reduction goal and reach Murphy 3.0 of our capital allocation framework, especially with current oil prices. Looking forward to reaching this next step and further increasing shareholder returns to 50% of adjusted pre-cashflow later this year. Slide five, Murphy produced at the high end of guidance at 170,000 barrels equivalent in the first quarter of 24 with 89,000 barrels of oil per day. We achieved a slight premium to WTIs. We realized $78 per barrel and I realized the NGL price is $23 a barrel and that gas was $2.12 per thousand cubic feet. Overall, we generated 746 million of revenue in the quarter excluding our non-controlling interest. I'll now turn the call over to our Executive Vice President Chief Financial Officer, Tom Morales for an update on our financial results, Tom.

Thank you, Roger. And good morning, everyone. Slide five, in the first quarter, Murphy reported $90 million of net income or 59 cents per diluted share and $131 million of adjusted net income or 85 cents per diluted share. We achieved $205 million of adjusted EBITDA due to a combination of strong production realized prices with $264 million of accrued capex excluding non-controlling interest. Overall, as Roger mentioned previously, we had an outstanding quarter in returns to shareholders as we repurchased $50 million of stock, paid a higher dividend and increased our cash balance. In total, we returned over 60% of our free cash flow all while supporting a front-end loaded capex plan with approximately 60% of spending in the first half of 2024. Slide six, Murphy maintained strong liquidity in the first quarter with $1.1 billion as of March 31st, including more than $300 million in cash and equivalents. I'm pleased that during the quarter, we received positive outlooks from both Moody's and Fitch revised from stable outlooks previously with the corporate ratings affirmed at BA2 and BB+. At quarter end, we had $1.3 billion of senior notes outstanding with a long dated weighted average maturity of nearly eight years. We remain on track for further debt reduction this year and I look forward to reaching Murphy 3.0 with total debt of $1 billion before year end. Slide seven, at Murphy, we seek to continually minimize our impact on the environment, whether that's using natural gas rather than diesel to fuel our onshore operations or utilizing recycled water for our well completions. We also support the communities in which we work, like the city of Uvalde in South Texas or here in Houston. Because of this service, we have been presented with awards such as the United States President's Volunteer Service Award from the Houston Food Bank. And I look forward to Murphy developing further initiatives to enhance our positive impact. With that, I will turn it over to Eric Hamley, our President and Chief Operating Officer to discuss our operational updates.

Thank you, Tom. Slide 10, our Eagleford Shale Wells performed above expectations in the first quarter, achieving total production of 29,000 barrels of oil equivalent per day with 86% liquids volumes. Our operating partner brought online four Tilden wells during the quarter, while Murphy progressed our 20 well operated drilling program for the year as planned. We are on track to bring seven operated Catarina wells online in the second quarter, plus an additional four non-operated Tilden wells. Slide 11, in the Tupper Motney, Murphy produced 348 million cubic feet per day and progressed our 2024 well delivery program with 13 wells that are either now producing or will be online in the near term. This will complete our plans for the year. We are excited to announce that Murphy has joined the Rockies LNG Partnership, which may create future LNG opportunities for our Tupper Motney acreage as projects in the area near completion. This partnership is comprised of Western Canadian natural gas producers driving LNG export optionality and we are eager to be a part of it. Murphy maintains a strong price diversification strategy mitigating against eco price exposure. For the first quarter, we sold approximately half of our natural gas volumes at the Chicago, Don, Malin, Emerson, Henry Hub, and Ventura price points. Slide 12, our K-Bob DuBrunet asset produced 4,000 barrels of oil equivalent per day with 68% liquids in the first quarter of 2024. We progressed our development program for the year and have three operated wells coming online in the second quarter as planned. Slide 13, our Gulf of Mexico assets produced 73,000 barrels of oil equivalent per day with 82% oil volumes. This production was impacted by approximately 13,000 barrels of oil equivalent per day of planned downtime events during the quarter. Murphy is advancing our development program for the year and we look forward to bringing online the sizable Calisee number four well in the second quarter as we found approximately 200 feet of net pay when drilling. We're also progressing the drilling of a new well at our Normont field, which is scheduled to come online in the third quarter. Additionally, our operating partner has brought online wells at the St. Malo and Lucius fields during the quarter. In offshore Canada, we produced 6,000 barrels of oil equivalent per day in the first quarter according to plan. Slide 14, during the first quarter, we completed the zone changes on the Marmellard number one and number two wells as planned, as well as the subsea equipment repair at Mormont number two. Murphy also initiated work on the Niedermeyer number one well work over with the plan now updated to drilling a side track well, which will delay the online date to the third quarter of 2024. Our work over expenses, which are included in our lease operating expenses, total $50 million for the first quarter with $65 million forecast for the second quarter. This figure includes the cost of the Niedermeyer side track well. Additional work is planned later this year at the Dalmatian number two well for the subsurface safety valve repair, as well as the non-operated Kodiak number three well stimulation and zone addition. Slide 15, in Vietnam, we have been progressing our plans for our Loc Da Vong field development project, including advancing award of major contracts this year. We look forward to begin drilling our development wells in 2025 and remain on schedule for achieving first oil in late 2026. Slide 17, in the Gulf of Mexico, we're excited to begin our 2024 exploration program. Our operating partner is currently drilling the Ocotillo exploration well. Immediately following this well, the rig will shift to drill the nearby Orange exploration well. These two Miocene prospects are located near existing infrastructure and could be brought online quickly if either is a discovery. Also in the first quarter, we expanded our portfolio and were awarded six deep water blocks from the Gulf of Mexico federal lease sale 261. Slide 18, we're continuing preparations for our Vietnam exploration program later this year and are excited to have contracted a rig, which is currently drilling in country. Murphy will first bud the high Suvong exploration well in block 15 to 17 in the third quarter and target a mean to upward gross resource potential of 170 to 430 million barrels of oil equivalent. The rig will then move to drill the Loc Da Hong exploration well in block 15, 105, targeting a mean to upward gross resource potential of 65 to 135 million barrels of oil equivalent. We look forward to seeing the results of these wells as they provide the potential to create a more sizable business in Vietnam. Slide 19, our seismic reprocessing work continues to progress for our acreage in Cote d'Ivoire and we are pleased at the multiple opportunities available across exploration play types. Importantly, ENI recently announced positive results from its Moraine 1 exploration well on the Colau discovery nearby. Murphy is excited at this news and I note that our block CI 502 in particular is very near this discovery. In general, our Cote d'Ivoire acreage position is now bookended by two significant ENI discoveries. We will continue to progress our analysis of the data as it comes in with the final seismic data due by year end 2024. And with that, I will turn it back to Roger.

Thank you, Eric. On slide 21, for second quarter 24, we forecast total production of 176,000 to 184,000 equivalents per day with 93,000 barrels of oil during that period. This range is impacted by 2000 barrels of oil equivalent today of offshore non-op unplanned maintenance, primarily related to a third party downstream facility, 1,250 barrels equivalent per day of the Eagleford shale downtime as we have offset frac impacts and a significant downtime of 11,700 barrels equivalent per day at Tupper Montney for plant maintenance that's ongoing. Murphy plans to spend approximately 325 million of accrued capex in the second quarter. The full year 24, we're maintaining a production guidance of 180 to 188,000 equivalents per day with 52% or 95,000 barrels a day of oil. Our this guidance is supported by stronger on-well performance and better results at non-operated offshore fields. We're also maintaining our capex range at 920 million to 1.02 billion, excluding NCI. These ranges will support us achieving our 2024 debt reduction goal of 300 million, thereby allowing us to reach Murphy 3.0 and enhance our shareholder returns. On slide 22, effective at year end, our long-term strategy remains unchanged since we first disclosed the refresh projections following last year's opportunities captured in Vietnam and Cote d'Ivoire to support our new opportunities and long-term oil production growth. We'll continue to support and grow our returns to shareholders during this time. In particular, we'll be executing Murphy 3.0 of our framework after reaching our debt reduction goal of this year. Longer term, we plan to reinvest approximately 45% of operating cashflow, enabling us to achieve average production of approximately 210 to 220,000 equivalents per day and as always, over 50% oil weighting. Murphy will continue generating ample free cashflow to allocate towards further shareholder returns, accretive investments, as well as supporting exploration success. Additionally, as part of this plan, remain committed to achieving metrics that are consistent with investment grade rating. And I'm pleased that the rating agency outlook improvements achieved this spring that Tom just spoke of. On slide 23, I'm glad to have a solid first quarter behind us as we continue to execute our plans for the remainder of the year. A long history of consistently returned to shareholders will expand as we reach Murphy 3.0 later this year. We're already ahead of the game with share repurchase in the first quarter. I view our 24 debt reduction goal as a given. I look forward to buying back more stock to enhance shareholder value. Additionally, we have exploration upside with drilling two wells in the Gulf of Mexico and two wells in Vietnam. Our future is bright, especially consider a long runway of Gulf of Mexico projects, as well as significant future locations across our North American onshore business and our exploration upside. As we approach annual meeting season, we often benchmark our peer group on 2023 10K data. When doing so, we find that Murphy is rated one or two in many categories, a few of those. Pre-cash flow for production, the per debt adjusted share growth, production per debt adjusted share growth, lowest reinvestment rates, debt reduction, total debt, debt due 24 to 26, debt to EBITDA, total cash return per shareholder change year over year. And lastly, GNA for EBITDAX, solid company, solid plan, diverse portfolio, exploration upside, locations sustainable, a long history of shareholder returns. That's Murphy Oil Corporation. As always, I wanna thank our outstanding employees for the consistent effort and determination to help us reach all of our goals. With that, that's the end of our

prepared remarks today and we look forward to our questions.

Ladies and gentlemen, if you have a question, please press start and followed by the one on your touchstone phone. You will hear a prompt that your hand has been raised. And if you wish to decline from the polling process, please press star followed by the number two. If you're using a speakerphone, please leave the handset before pressing any keys. Your first question comes from the line of Neil Dingman from Tros Securities. Your line is open.

Morning, thanks for the time. Morning, Roger. My first question just on shareholder return, you just sort of hit on this, Roger, but I just wanna go over. Specifically, could you or Tom remind me what bonds, if any, you were able to repay early and then more, I guess more importantly, once you get under that billion or to Murphy 3.0, besides just stepping up the shareholder return, could we see more expiration work or what else could we see because obviously your debt at that time will be well under control. So I'm just wondering, besides stepping up to shareholder return, is there something else we would see with that incremental free cash flow?

Thank you for that question, Neil. It's a big key part of our strategy. I'm gonna give you a big high level picture and let Tom talk about the specific bonds. We need to think about this framework as a yearly matter. We easily can forecast as you and all of your peers are that we'll easily get rid of this $300 million of debt. There's nuances to calling the debt at different opportunities. We also have an internal target in our plans of how much stock we can buy. Nobody wants to buy back stock more than me and we see the debt as a given. So we're already ahead of the game on the stock. We have an eyeball at how much stock we wanna buy. And I would see that going along if the debt goes into the third quarter, that's still something we'll be able to do as we go along the way if you follow me on that. So our strategy is that as far as long-term, we wanna keep our plans, we keep our low growth plans. We do not see changes to that plan at any time that I just reiterated. And we want to continue to buy back this stock while it's undervalued. And as you know, by yourself and many of your peers, we'll be ranked number one in cash flow through 26, available to our market cap. And that's gonna make us have a really big advantage and we're not really into changing that right now. So I'll let Tom talk about the specific notes. All right, thanks Roger.

Yeah, Neil, we got a little over 300 million to go to reach Murphy 3.0. And we've got more, plenty available in our 2027 notes. Those are callable today. And the balance is around 440 million of 2027 notes. And then our 2028 notes will be callable in July of this year. Now you asked about, once we get to Murphy 3.0 and we go into this 50% to shareholders, 50% to the balance sheet, the way we kind of think about that is, Murphy 2.0 was about, it made more of a defensive move, making sure we got our balance sheet in a robust shape. Murphy 3.0 gives us a chance to be positioned for more of an offensive move. Whether it's dry powder or more opportunities to return to shareholders, either through buybacks or even dividends.

Thanks, Tom. And then, the couple of the answers. And then just secondly, Roger, maybe high level on valuation. Just continue, it's hard not to notice, that you all trade below some other companies that have materially less production. I'm just wondering your opinion, do you think the market is just still not appreciating the stable offshore production of y'all? I mean, I look at your inventory, I look at the production, especially not just the onshore, but the offshore development activity, and continue to be sort of surprised just the discount. I just would love to hear your opinion on why this discount that I can't piece together.

Thanks for that question, Neil. Really love that question. This is my 12th year doing this. It used to make me real upset about those matters. But today, we're just looking to buy back stock. And we're gonna buy back stock until we do better. We have our balance sheet in order to do so. I just rattled off in a long list of positives about our company is solid. Can't have those attributes about running a good solid company. I believe it must be the market cap of our company would be similar to all shale. And all shale doesn't have a work over. All shale is a perfectly organized drilling game plan. If we were all shale, I could tell you exactly the production by quarter, it's almost better to have the same product capex every quarter. But if you look at the free cash flow and uniqueness of our company and the deals that we've done and the M&A and all the opportunities we have, it's because we're in the old business. We're in different aspects of the business. We now have ourself in a situation where growth has slowed. Buying back stock is in vogue, but we're gonna have the best balance sheet and buying stock. We'll be patient and get into doing that, especially in 25. And then we'll go with the valuation from there.

Makes sense, well said, thank you, Roger.

Your next question comes from the line of Leo Mariani from Rod MGM, your line is open.

I wanted to touch base on the Gulf of Mexico production here real quick. I heard some of these numbers, right? I think you guys said you had 13,000 barrels a day, equivalents of downtime in the first quarter, 2,000 equivalents of downtime in the second quarter. So I guess that's a plus 11,000 barrel a day improvement in two queue. But just kind of looking at guidance, it looks like you're guiding up around 4,000 barrels a day. So just wanted to get a sense of the Delta. Is that just kind of natural declines there in the Gulf?

I'll let Eric handle that for you, Leo, and thank you for that question.

Yeah, Leo, thanks very much. We have quite a bit going on with our Gulf of Mexico program this year. We've noted that we have a number of high rate wells that are not currently producing, in particular the Niedermeyer well that we're doing a work over, which has now become a sidetrack. That's a high rate well, about 4,000 barrels a day that should come online early in the third quarter. And then in the middle of the year, we have work going on at our non-OPCOTIAC and our operated Dalmatian to increase production there. So if you think about those just wells that have historically been producers for us that are coming online toward the middle of the year, you'll see a ramp. Along with that, we have our Calise-Mormont program that will add volumes that will help offset declines. So as you march through the year, Gulf of Mexico production will increase, and production in Gulf of Mexico in the first quarter was around 73,000 barrels a day, and ought to be up 9,000, 10,000, 11,000 barrels a day by the end of the year. The end of the last quarter ought to be something like that increase. So offsetting decline with new production and restoring wells to production that have been offline temporarily.

Okay, that was very helpful in terms of the explanation. And I wanted to also have just kind of a similar line of questioning around the Eagle Ford. Looks like that production kicks down a little bit in the second quarter. You guys cited some maintenance that's ongoing, but could you maybe just kind of discuss how the Eagle Ford production trajectory should play out as we roll into 3Q and 4Q?

Yep, as you noted, we do have a little bit of downtime in the second quarter. That's primarily offset frac impact because we have an active completion program going in the second quarter. That program continues into the third quarter. The bulk of our operated wells, which generate most of the new production in Eagle Ford come online in the third quarter. So you ought to see production peak in Eagle Ford in the third quarter and be relatively similar in the fourth quarter. Okay, thank you. For the full year, we're predicting a 30,000 barrels a day for the Eagle Ford.

Okay, that's helpful. I appreciate it. Thanks. Thank you, Leo. Appreciate it.

Your next question comes from the line of team residents from Key Ban Capital Markets. Your line is open.

Good morning, everyone. Hi, Roger. Thanks for taking my question. I was hoping to dig in a little more on a follow-up on the last question on the Gulf of Mexico. You know, the Niedermeyer, obviously, prolific well, 4,000 a day. You said the work-over activity became a sidetrack. I was wondering if you could give a little more context on kind of what changed and if you expect that back at full capacity in early 3Q.

Eric, to handle that for you, it's just oil field there, Tim, this morning.

Yeah, so what happened with that well is the work-over that we had planned when we got on the well, we expected that the problem was a packer that was leaking. We confirmed in the early stages of our work-over that that was indeed the problem. As we progressed with the work to pull the packer in tubing, we were trying to isolate the lower completion from the upper completion, so basically the productive connection with the reservoir from the tubular goods in the top part of the well, and we were having difficulty isolating the lower completion and decided that the best path forward to have the best success going forward with that well was instead of continue on that path of continuing to fight to get isolation of the lower completion, that we would sidetrack the well, which would give us an opportunity to have a completely new completed well with a very short offset from the existing location. We have sidetracked that well. We like what we've seen so far. We're going to move forward with a completion that should be a brand-new fresh completion, which has the best mechanical outcome and should provide the best production rate opportunity. So it should be reduced in line or better than the well that we're leaving behind.

Okay.

And one note on that, Tim, one note on that, Tim, it's 4,000 net. All these wells we have make 16 to 18,000 barrels a day gross. These are big wells. We happen on 30-something percent of this one. So it makes way more than four a day.

Yeah, sure. Yeah, I get that. Okay, that's all I had. Thank you. Thank you, Tim.

Again, if you have a question at this time, please press star followed by the one on your touch-tone phone. You will hear a prompt that your hand has been raised. And if you wish to decline from the polling process, please press star, then followed by the number two. Your next question comes from the line of Charles Mead from Johnson Rice. Your line is open.

Good

morning,

Charles. Good morning, Roger, to you and the rest of the Murphe team there. My first question is on 2Q CAPEX. The 325 guide is, you call it 60 million higher than what I was looking for and I think what some other people were looking for. It looks like what you've already laid out, that the big driver of that is really the US onshore completion pace, drilling completion, or I guess I should say North America onshore drilling completion pace. But also that there's a lot of work going on in the Gulf of Mexico. Are those the two big pieces or are there other drivers that are contributing to what looks like high CAPEX and 2Q?

Thanks for that question, Charles. I'm going to just frame a little bit, let Eric get into the details. So we've set out along over 60% of our CAPEX in the first year and we're still within a percent of that. This is timing of various matters. Timing, actually we've drilled faster and completing faster in the onshore business and we have non-up matters timing on the other. I'll let Eric get into the detail after that. So we feel that we're still in line, everything's in line for our debt, everything's in line, buyback stock. We just moved a few percent of the CAPEX to the left. That's really no more than that. Eric will give you a detail of that.

Yeah, thanks Roger. As you noted, most of the change is driven by the timing of our onshore North America drilling completion program. That's over $30 million of the change. So that's shifting from later in the year into the second quarter. And then offshore, about $15 million of equipment, subsea equipment related to our Caloosie-Mormont program. We moved some spending that we expected in the fourth quarter up into the second quarter as we pivoted during the time we had our Mormont number two subsea equipment issue. And then some seismic spend moved from the first quarter, the second quarter, you know that we had lower CAPEX than our original guide in the first quarter. So some of the spending we thought would happen for -D&C related activities, including seismic and our Lochtevong development spending moved from the first quarter of 24 into the second quarter of 24. And that's another $11 million or so. So that describes most of the changes and the movement of CAPEX really, as Roger pointed out, we're just phasing of spending and not overall spending is changing.

Got it. That is helpful detail. And then, Eric, I want to go back to a comment that you made about this. It seemed like you were pretty positive on this Caloosie number two development well, I think it is. And I think you, I believe I heard you mentioned that there are over 200 feet of pay. And I'm wondering if you could give us two aspects of context and anything else you want to add. First, how does that 200 feet or whatever you saw in this most reasonable, how does that compare to the initial well there? And then the second piece is that all in one zone or is that across a few different zones? And so we're gonna have a, I guess what I'm getting at, is this gonna be a monster one zone completion or is this the more typical, you have 60 feet in three different zones kind of thing?

Yeah, thanks for that. I appreciate the opportunity to talk about it. This particular well, the Caloosie four well was targeting a reservoir that was not in our initial development of the field. As we develop the field, we identified some additional opportunities. This particular one is targeting a shallower reservoir in an -to-position. And we, so we penetrated this reservoir as we were going to deeper zones, which were the target of our main field development. This is sort of an additional set of volumes that we were able to develop after the initial development program. And we're excited about it. It is in one zone. It's a very nice looking reservoir with high reservoir quality, should produce very well for us here as it comes online soon. So if you think about our overall Caloosie-Mormont Samurai development, we had an initial set of wells, which we've talked about how they'll do production-wise. In the development, we have Caloosie and the two Mormont wells that we're doing this year are similar. They're targeting zones that were not contemplated in initial development. They're additional volumes, which will allow us to extend the plateau of our total Caloosie-Mormont Samurai development. So from that perspective, we're really excited. This development has been tremendous for us with very fast payout already happened and additional volumes going forward with plateau production out into 2025, 2026.

Got it. That's great detail. Thank you. Thanks, Charles. Appreciate it. There are

no further questions from our phone lines. I would now like to turn to call over to Roger Jenkins for any closing remarks.

Appreciate everyone dialing in today. Had some good dialogue there with our business. We're very, very pleased with our business, looking forward to the rest of the year and beyond. Appreciate all the attendance today and we'll be seeing you soon. Check in with our IR team if you have any further questions. Thank you all.

This concludes today's presentation. This conference call, you may now disconnect.