Murphy Oil Corporation (NYSE:MUR) Q3 2024 Earnings Call Transcript

Murphy Oil Corporation (NYSE:MUR) Q3 2024 Earnings Call Transcript November 7, 2024

Murphy Oil Corporation beats earnings expectations. Reported EPS is $0.74, expectations were $0.68.

Operator: Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2024 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 third quarter earnings call today. With me are Roger Jenkins, chief executive officer; Eric Hambly, President and Chief Operating Officer and Tom Mireles, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we 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 our non-controlling interest in the Gulf of Mexico. Slide 2. 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 may exist that cause us the results to differ. For further discussion of risk factors, see Murphy’s 2023 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. Roger?

Roger Jenkins : Thank you, Kelly. Good morning, everyone, and thank you for listening in on our call today. As we turn to Slide 3, I’d like to reiterate our corporate priorities of delever, execute, explore, and return. In the third quarter, we focused on executing our operations, advancing our exploration program, and progressing shareholder returns. Murphy produced 185,000 barrels of oil equivalent per day during the third quarter. We progressed our Gulf of Mexico well program and brought online Eagle Ford Shale wells as planned. I’m pleased to announce that early in fourth quarter, we initiated construction of the Loc Duvang production platform for our field development project in Vietnam. Also, in the third quarter, we began drilling the Hai Su Vang-1X exploration well, which initiated our two well exploration program in Vietnam.

I’m pleased that the progress we’ve made at returning funds to shareholders in Murphy 3.0 while maintaining a leading balance sheet. During the third quarter, we repurchased $194 million of stock or 5.4 million shares. Year-to-date, Murphy has repurchased $300 million of stock or 8 million shares at an average price of $37.46 a share. Overall, we’ve reduced our share count by 16% since the year end of 2018. On Slide 4, last quarter, we announced a remove in the Murphy 3.0 of our disclosed capital allocation framework. As a result, we now target allocating a minimum emphasis on minimum of 50% of our adjusted free cash flow to shareholder returns, primarily through buybacks. The highlight that this is a minimum return threshold, which allows us to buy more stock in times of price dislocation such as the past quarter and certainly now.

Most significantly year to date, we returned 110% of our adjusted free cash flow to shareholders as buybacks. A reminder, adjusted free cash flow from Murphy is after our extensive dividend that we pay. As described in our framework, the remaining adjusted free cash flow will be allocated to our balance sheet as we’re committed to our $1 billion long-term debt goal. I’m proud of what our team has accomplished in recent years with our balance sheet improvements, in particular since launching the capital allocation framework two years ago. Since that time, we’ve repurchased $450 million of shares increased our dividend by 70%. As of November 5, we have approximately $650 million remaining under our approved $1.1 billion total share repurchase authorization.

On slide 5, Murphy produced an average of 185,000 barrels equivalent in the third quarter with 88,000 barrels of oil. As usual, we realized the premium to WTI with the realized oil price of nearly $76 per barrel. While I realized NGL price was nearly $22 and natural gas was a $1.47 per 1,000 cubic feet helped by price diversification and fixed price forward sale contracts in Canada. As a result, Murphy generated over $700 million of revenue in the quarter, excluding our non-controlling interest. I’m now going to turn the call over to our CFO, Tom Mireles, for an update on financial results. Tom?

Tom Mireles : Thank you, Roger. Good morning, everyone. Slide 6. Murphy reported net income of $139 million in the third quarter or $0.93 per diluted share and adjusted net income of $111 million or $0.74 per diluted share. Overall, we generated $397 million of adjusted EBITDA during the quarter with $211 million of accrued CapEx excluding non-controlling interest. As a result of the free cash flow generated during the quarter, we were able to repurchase nearly $200 million of stock at an average price of just over $36 per share. Year to date, we have repurchased $300 million of stock and reduced $50 million of long-term debt. Slide 7. Murphy’s priority to delever in recent years has led us to achieve a strengthened balance sheet that has positioned us to withstand commodity price volatility.

I am pleased with the very successful capital markets transaction that Murphy executed early in the fourth quarter with extending our debt maturity profile through the issuance of senior notes due 2032 and the partial tender of notes due 2027, 2028, and 2029. We plan to call the remaining $79 million of senior notes in the fourth quarter so that the transactions are debt neutral. Additionally, we entered into a new five-year $1.2 billion senior unsecured credit facility this quarter. This represents a 50% increase from our previous facility, highlighting the strength of our credit, and provides Murphy with an additional $400 million of liquidity. Slide 8. We have a robust sustainability report that details Murphy’s ongoing environmental stewardship, strong governance oversight, and positive impacts on our community.

Murphy remains focused on being a responsible company, and we look forward to achieving our emissions goals. With that, I will turn it over to Eric Hambly, our president and chief operating officer, to discuss our operational updates.

Eric Hambly : Thank you, Tom. Slide 10. In the Eagle Ford Shale, Murphy produced an average 32,000 barrels of oil equivalent per day in the third quarter with 72% oil and 86% liquids volumes. We continued to execute our well delivery program during the quarter and brought online 5 Tilden wells as well as 3 gross non-operated Karnes wells and 9 gross non-operated Tilden wells. Our program will continue in the fourth quarter with four plant to come online in Catarina as well as drilling eight Karnes wells to hold as DUCs in advance of 2025 completions. Historically, Murphy has not maintained a high DUC inventory at year-end. However, we are shifting to a more consistent rig schedule onshore, so we will be well-positioned to increase our Eagle Ford Shale production in early 2025.

I’m excited to see continued positive results from our optimized completion design, particularly achieving the lowest cost per completed lateral foot in Murphy history, with a 34% decrease since 2023. Our year to date 2024 program has also seen an 18% increase in completed lateral length and a 16% increase in pumping hours per day compared to 2023. Slide 11. Murphy produced an average 429 million net cubic feet per day in the third quarter from our Tupper Montney asset, which exceeded guidance by approximately 11 million cubic feet per day as our wells continue to outperform expectations. We maintain a portfolio of fixed price forward sales contracts to mitigate AECO price risk. And in the third quarter, this accounted for nearly half of volume sold.

Murphy also sold significant volumes at diverse price points, including Malin, Ventura, Emerson, Chicago, and Dawn. As a result of this price diversification strategy, we achieved a realized price of $1.35 per 1,000 cubic feet compared to an AECO average of $0.50 per 1,000 cubic feet. Slide 12. The Gulf of Mexico, Murphy produced an average 67,000 barrels of oil equivalent per day with 79% oil in the third quarter. We brought online the operated Mormont number 3 well and spud Mormont number 4 as planned in the quarter. And I’m excited at the initial results from drilling this new well. Additionally, I’m pleased with the results of our two new wells at Khaleesi and Mormont, which are each producing over 15,000 barrels of oil per day on a gross basis.

I’m also pleased to announce that our operating partner-initiated water injection at the Saint Malo Water Flood Project during the quarter. Recently, we started our first Murphy operated ocean bottom node seismic survey across the Khaleesi, Mormont, and Samurai fields and the nearby prospects. This improved technology will provide us with enhanced imaging across our development and exploration opportunities. In offshore Canada, where we produced an average 8,000 barrels of oil equivalent per day with 100% oil in the third quarter, non-operated Terra Nova production was impacted by additional downtime. As we previously announced, we brought online all planned workovers during the third quarter for $34 million total workover expenses. For the fourth quarter, we forecast $40 million of workover expenses at the operated Samurai number 3 and Marmalard number 3 wells.

We recently developed a mechanical issue at the operated Samurai number 3 well and have planned a rig workover to return the well to production before year end. Slide 13. In Vietnam, we’ve been progressing our field development plan for Lac Da Hong We achieved a significant milestone early in the fourth quarter as we initiated platform construction. Roger and I recently visited the shipyard, and we were very impressed with the project team and the construction yard. We expect to award our remaining major contracts for the project by year end, and I look forward to beginning drilling our development wells in 2025. Overall, Murphy remains on schedule for achieving first oil in late 2026. Slide 15. During the quarter, we drilled the operated Sebastian number 1 exploration well.

Non-commercial hydrocarbons were present and we plugged and abandoned the well. As we close out the year, we’re progressing plans with partners for our 2025 Gulf of Mexico exploration program with multiple opportunities across our 58 exploration blocks. Slide 16. I’m excited that we initiated our Vietnam exploration program as we spud the Hai Su Hong 1X exploration well in block 15 to 17 in the third quarter. After drilling this well, the rig will move to drill the Lac Da Hong 1X exploration well in block 15 105 in the fourth quarter. We forecast $30 million in total net drilling costs for the two wells. These opportunities provide the potential to create a sizable and meaningful business in Vietnam and I look forward to seeing the results.

Slide 17. Murphy continues to progress seismic reprocessing for our position in Cote d’Ivoire, and we expect to receive the final data before the end of the year. We have several interesting opportunities across exploration play types and are pleased with the identified prospects as well as recent nearby discoveries announced by other operators. We will continue our evaluation of the data as it becomes available, and we’ll begin likely begin planning an exploration program in late 2025 or 2026. Additionally, we remain on track for submitting a field development plan for the undeveloped pond discovery by year end 2025. Slide 19. For the fourth quarter, we forecast production of 181,500 barrels to 189,500 barrels of oil equivalent per day with 51% oil volumes and 56% liquid volumes.

This range includes 1500 barrels of oil equivalent per day of planned onshore downtime and 1,000 barrels of oil equivalent per day of planned downtime for maintenance at non-operated Terra Nova. Our fourth quarter forecast also includes planned accrued CapEx of $203 million. For full year 2024, we are tightening our guidance range to 180,000 to 182,000 barrels of oil equivalent per day with 50% oil volumes and 55% liquids volumes. As previously disclosed, production has been impacted by continued downtime at Terra Nova. We are maintaining our accrued CapEx range of $920 million to $1.02 billion excluding NCI. Slide 20. We share our multiyear plan each January. As we progress our budget for 2025, we are also evaluating our commodity price assumptions, spending, and production plans, and we will provide a full update with our fourth quarter results in January.

However, many aspects will remain constant. As we look toward the future, Murphy remains committed to our $1 billion long-term debt target. We’ll achieve this while reinvesting approximately 50% of cash flow in high-returning offshore projects as well as deep onshore inventory that together supports future oil-weighted growth for many years. We have exciting catalysts ahead with reaching first oil in Vietnam in 2026 and drilling high-impact exploration wells across the Gulf of Mexico, Vietnam, and Cote d’Ivoire. We also plan to continue rewarding our loyal shareholders with ongoing share repurchases and potential dividend increases, while achieving metrics that are consistent with an investment grade rating. And with that, I will turn it back to Roger.

Roger Jenkins : Thank you, Eric. As we get on Slide 21, I’d like to reiterate that we had another solid quarter results with our onshore assets performing well and exceeding guidance and continued execution of our Gulf of Mexico program. We were able to deliver shareholder returns through buybacks as prescribed in our capital allocation framework. We also enhanced our balance sheet and liquidity through executing capital market transactions early in fourth quarter. Moreover, we’re advancing our Vietnam development and exploration plans, and we look forward to expanding our portfolio with high-impact exploration opportunities. Well, this is my last call today. I estimate this is my 48th call starting in August of 2012 as COO.

I think I’m missing one along the way. I’d like to thank all our analysts that covered us all these years. Also like to personally thank Kelly Whitley for leading our IR efforts over the last nine years. Kelly, it does seem a lot longer, I must say. And, she’s one of the best there is. And our great IR team of Megan and Beth, I’d like to thank our dedicated employees for all their support. Also, I’d like to thank our shareholders, for their support of my 11 year plus, career as CEO. I wish Eric all the best. Along with Tom, we have an excellent executive team and a great plan. And I look forward to watch Murphy excel. Thank you all, and, go Tigers. Big game this weekend. Thank you.

Operator: Thank you, Roger. Ladies and gentlemen, we will now begin the question and answer session. [Operator Instructions]. Your first question comes from Neal Dingmann with Truist Securities. Please go ahead.

Q&A Session

Neal Dingmann: good morning, guys. And first, Roger, I want to congratulate you on the retirement here [Indiscernible] appointment. Roger, it’s been really appreciate all your help along the way. But again, congratulations. My first question today is on your 25 operations. Really what I’d say specifically, can you speak to next year’s plan? There’s a lot of volatility out there depending on what oil price is doing. I’m just wondering depending on a high or low oil price environment, would the offshore spend be the toggle or how different would the ‘25 plan be under a $60 versus $80 oil?

Eric Hambly : Neal, this is Eric. I’ll jump in to answer the question. The way we think about our program, we’ve communicated in the past that, our aspiration for our company from ’24 through ’26 is to have oil weighted low CAGR growth while spending approximately $1.1 billion of CapEx on average annual basis. We remain committed to that plan. If you look to 2025, I would anticipate production in ‘25 to be similar to slightly higher than 2024 and with significantly higher oil production as we expect Eagle Ford Shale production to be quite a bit higher based on the timing of new well delivery. In terms of CapEx allocation in a low-price scenario, that’s something that we’ll be evaluating obviously as we head into finalizing our budget. And we’ll look forward to updating you on that in our call in January.

Neal Dingmann: Love the optionality. Thanks, Eric. And then just second question on Vietnam. I just wondered from my education, just wondering could you remind me of the cost and potential upside of these Vietnam wells versus maybe like a typical shallow Gulf of Mexico well? And just wondering, have you all spoken about plans in Vietnam beyond these first two exploration wells?

Eric Hambly : Great question, Neal. We’re really excited about our Vietnam progress here. We made a really nice discovery that we’re developing in the Lac Da Hong field, which is a 100 million barrel project there on an equivalent basis gross. And, once we got moving on that development, we identified that we had a great opportunity in Vietnam with a long exploration running room on the two blocks that we have in the Cuu Long Basin. So, we got to drilling starting late in third quarter on the first of two prospects. The Hai Su Hong prospect is targeting a mean to of 170 million barrel oil equivalent to upward of over 400 million barrels, which is a really nice sizable prospect. If you compare that to the 100 million barrel Lac Da Hong field, obviously, it’s something that we’re really excited about.

It has the potential to be really material. After we drill the Hai Su Hong well, we’ll move to the Lac Da Hong and that targets a 65 million barrel mean to 135 million barrel upside type of opportunity. So, these two together have the potential to really allow us to develop a really meaningful material business in Vietnam, which might be able to produce, toward the end of the decade in the 30,000 to 50,000 barrel-a-day range. So really happy with the progress there. Really excited about, how we’re executing so far and been able to talk about results likely early next year.

Roger Jenkins: Just a bit more color on that, Neal. I think it’s really unique for a company to have a go to development while having a big exploration project next door, infrastructure advantages, a copy of what we did in Malaysian shallow water where we had a very significant business, both Tom and Eric ran that business before. We’re doing the same thing in Cote D’ivoire, big exploration, highly sought after with a possible development at Pond. So, we got exploration on both ends of the world with a possible development on one and the development on the other. Very unique, very changeable for our company, and a really good set of business that was put together here by our team.

Tom Mireles: Yeah. Just last comment for me, Neal, on in terms of follow on with success with these blocks, not only we’re excited to develop them, but we have quite a large inventory of remaining prospects on both blocks. Obviously, some of the prospects would be impacted by the results from these wells. But even with prospects that have no dependency from what geology do we find, we have quite a few other opportunities that we’ll be evaluating in future years.

Neal Dingmann: Thank you, both.

Operator: Thank you. Your next question comes from Carlos Escalante with Wolfe Research. Please go ahead.

Carlos Escalante: Hey, good morning guys. First of all, Roger, congratulations. Eric, congratulations on the role as well. Roger, I think Alabama might win this weekend. So, hey, missus Paul. You’re a retirement department.

Roger Jenkins: I thought you’re way too smart for that, honestly.

Carlos Escalante: All right. I’ll get there. So, let me start with just picking up on the previous question. Obviously, there’s only a handful of exploration plays out there. And given that, there’s inevitable volatility on share prices and given that strategy. So how do you see your options for consolidation moving forward in order to mitigate some of what’s going on and what’s happened over the course of the quarter? Obviously, this is shortsighted, but just would like to get your perspective on how you see the space now, and entering to 2025, especially as the balance of the year and the geopolitical and political context is falling into its place?

Roger Jenkins: I’ll let Eric answer most of that. But really, Murphy with our balance sheet and our setup and our international experience, we’re prepared to move and do whatever is necessary for the highest return, really have budgeting focused on really free cash flow maximization so we can execute our capital location framework. Political ins and outs will be positives or negatives on either side. We never really focused on that. We just focus on executing our business. And one thing about Murphy’s, we have — we never caught up with one kind of vendor, one kind of pipe, and one kind of regulator. We work in Canada. We work in the Gulf. We work in West Africa. We work in Vietnam, and elsewhere. And we have the ability to work anywhere in the world.

We have an executive team that’s worked and lived internationally. So really a different kind of animal as regulatory outcomes of singular elections. We pride ourselves on that. And I will say that in both Cote D’ivoire and Vietnam, we’re incredibly welcome there. But these governments, they’re very happy to have a company like Murphy with super major execution ability, which we all worked in super majors. That’s what we built here at Murphy. So, we’re really advantaged in any kind of thing with this particular outcome from the election this weekend. Of course, have less regulatory for us involving Gulf of Mexico. Probably advantage as to offshore leasing, corporate taxes, and different things. But all those things have to come to bear, and we’re just moving forward, Eric, if you’d like to add to that.

Eric Hambly : Yeah. Just a couple of points like to make. We have in the past referenced the fact that within our existing portfolio investment opportunities, we have an ability to grow and then maintain our offshore scale from what the investment opportunities we have in our discovered fields and the fields that are producing now. We have a deep bench of investment opportunities with very low break evens, most of them below $35 a barrel. In our onshore, we have an extensive shale oil inventory of locations, 1,200 locations in Eagle Ford, nearly 500 locations in the [Indiscernible] that allow us for many decades to be able to invest there and maintain the oiliness and the scale of our business for multiple decades without ever making another discovery and without making an acquisition.

So, we feel we’re very well positioned to execute a nice single CAGR growth, oil weighted, high returning cash to shareholders type of business for the next several decades. I think that’s fairly unique. It’s also fairly unique that for a company that can do all that, we also have material exploration opportunities that we’re progressing in the near term. We’re really excited about the Vietnam opportunities and we’re getting very excited about our Cote d’Ivoire potential exploration program kicking off in late 2025. So, we feel really well positioned with our portfolio, both our investments to make and the exploration that we’re doing and happy with kind of how we’re heading forward. You did ask a question about consolidation, and I wasn’t quite sure how you frame that.

And maybe you could, reask that. I can help answer that question for you.

Carlos Escalante: Sure. Well, I guess my question was more on the opportunities that you have both onshore and offshore or the optionality that you have onshore and offshore provide you with the ability to create consolidation opportunities in both spaces. So how do you see that, and how do you think of that in terms of mitigating the current risk, in terms of share price volatility? And that was my point about there’s only a handful of exploration plays. And it seems like over the past quarter, they were hit harder for that same reason. So, wondering how you think about expanding that inorganically as opposed to what you’ve been doing, which is exploration led.

Eric Hambly : Okay. Yeah. Thanks for the clarifying. So, I guess let me frame that, and, Roger, feel free to jump in. We are really happy with the exploration portfolio that we have. We do consistently evaluate opportunities for M&A across the space, primarily in the offshore where we think we have a competitive advantage. We have proven over the last decade to be a very active with successful M&A, made really nice, divestiture in Malaysia in 2019, made great acquisitions in 2018 and 2019 in the Gulf of Mexico, built a very nice Deepwater Gulf of Mexico position, partly through successful exploration and partly through M&A. And we look at all those opportunities to maintain and grow our business. We’re very much interested in growing our exploration portfolio.

It’s common when we make an acquisition that those assets come with production something to be developed, and a portfolio of exploration blocks, which we’ve been exploiting and happy to do that. I don’t imagine we’re very likely to spend a lot of money to enter into a block that someone just made a discovery on to beef up our portfolio like some people have been doing in Namibia. We chase low cost entry, underexplored basins, have the potential to deliver large prospects with relatively low well cost. That’s kind of what our focus is. A little more of an organic bent, but we’re always watching to see what we can find that may be advantaged from a to us from inorganic perspective.

Carlos Escalante: Sure. Okay. Thank you. And then just a quick follow-up, which was my second question. On Terra Nova, it has had plenty of downtime and you quote this quarter around additional downtime that has impacted production. Now there has been some chatter about the operating party potentially disposing of it. So, I wonder if this would be an asset that you would ever consider on operating. Obviously, I know you don’t speculate on rumors, but, what are your thoughts and how do you see it falling into your greater portfolio in terms of priority?

Eric Hambly : Yeah. So, we’re at 18% working interest owner in Terra Nova. We’ve been extremely disappointed with the performance of the asset from a runtime perspective. If you contrast how we do in our operated assets, for example, in Kings Key, we produced that asset with a 98% uptime. Terra Nova has been averaging about a 55% uptime. We expected that they would do 75% to 80%. So, our historical guidance has reflected that we thought they could achieve a 75% to 80% uptime. They’ve actually been doing about 55%. It’s been frustrating and disappointing. We are working with our partner group to try to help improve operations where we can. As a non-operated 18% owner, it’s very challenging to do that, but we’re doing what we can.

Our fourth quarter guidance reflects a lower production level than we might have historically thought about because of the ongoing downtime that they’re experiencing. In terms of future change in operatorship, that’s really something that the operator would have to think about. We’re extremely unlikely to make any type of effort to operate at 18% working interest, just really not something that will happen. And there’s no language in the operating agreement where that would come to bear. So, we will sort of watch and see and try to help. And, if the operator has a strategic alternative for the asset, we’ll monitor that as well.

Carlos Escalante: Got you. Thank you, guys. Congrats again.

Operator: Thank you. Your next question comes from Leo Mariani at ROTH Capital. Please go ahead.

Leo Mariani: Hey, good morning here. Just wanted to follow-up a little bit about some of the comments you all made here. I guess it looks like that you’re drilling in your onshore areas in the Eagle Ford in the fourth quarter. I think you’re also drilling maybe some Montney and Duvernay wells. If I heard you right in the call, you’re expecting Eagle Ford production to start growing early next year, a little bit different sort of plan than you kind of had in the past. Sounds like you’re getting a bit of a head start there. Do you see a similar trajectory? Do you expect to start growing Montney early next year as well as Duvernay as well from some of the fourth quarter drilling and just get after the onshore in general a little bit earlier in the year to smooth it out?

Roger Jenkins: Thanks, Leo. That’s a great question. What we’ve been trying to do with our Eagle Ford business this year is to have a more consistent drilling profile, which will have allow us to have earlier average online timing of new wells in 2025. We intend to maintain that type of a profile going forward. So, with relatively similar level of CapEx, we expect to be able to deliver a little bit higher annual average with bringing our wells slightly sooner. We are drilling wells in the fourth quarter in our Karnes area and those will come online relatively early in 2025. I think once we establish that, you’ll see that we were able to maintain slightly higher average production. So, Eagle Ford production may grow 3,000 or 4,000 barrels a day on an annual average basis in ‘25 compared to 2024.

For onshore Canada and specifically in our Tupper asset, we expect to get to work drilling their first pad in the last month of the year. That’s been sort of normal for us over the last few years. We have a very limited program required in that Tupper asset to keep our plant capacity full. And so, I expect when we finalize our budget, we’ll have a limited number of wells that will be done drilling early in 2025 and completing soon after. And that’s pretty consistent with how we’ve operated the asset for the past few years. And at least in the near term, we plan to keep Tupper right at plant capacity with the delivery of our new well program and throughout the rest of the year have a little bit of decline. So, we’re not always at plant capacity, but we’ll be touching it with the delivery of our new wells.

Hope that frames in terms of delever on so assets for you?

Leo Mariani: No, that’s helpful for sure. And just wanted to touch a little bit on a workover expenses particularly up a little bit in 4Q versus 3Q. And I think you detailed some of that in your prepared comments for the, I guess, the well that kind of went down, you’re going to have to get out there and remediate a little bit. But just in general, I mean, it seems like your workover costs have kind of been running maybe a little bit higher this year versus last. What’s your expectation on that? I mean, do you think that that can start to drop a fair bit as we get into 2025? Or perhaps just some of the wells, they tend to get a little bit older from time to time and kind of require a little bit more TLC. Can you just provide a little bit more perspective around that?

Roger Jenkins: Yeah. Thanks, Leo. What I would say is this year our workover expense was quite a bit higher than we’ve seen or would we normally expect on a typical year. In the third quarter, we were able to complete the workovers that we anticipated at the time primarily toward the early part of third quarter. So, workover expense was a little bit lower. As we’re heading into the fourth quarter, we’re planning to work on the Samurai Number 3 well, which is up 50% working interest, so a little higher ownership than sort of our average offshore opportunity. And then also the Marmalard well will start this quarter and then finish it up next quarter. And after that, I don’t anticipate any workovers of significance. It’s not something that we build into our plans unless we’re aware of a specific well opportunity, to return a well to production.

It’s not routine in our business to have this type of thing happen. It’s quite unusual. And unfortunately, 2024 has been a bit of an outlier for us, and we’re happy to see the end of it approaching soon.

Leo Mariani: Okay. Thanks.

Operator: Thank you. Your next question comes from [Indiscernible] at Goldman Sachs. Please go ahead.

Unidentified Analyst: Hi, good morning and thank you for taking my question. I was just wondering if you could talk a bit more about the role you expect the Canadian onshore position to play in your portfolio over time and then more broadly your view on the benefits of asset diversification. Thank you.

Roger Jenkins: I’ll let Eric answer that question, but first I have to frame that we’ve been in Canada for probably almost 70 years. We’re very known operator there. We have a very unique position in the Montney we built from scratch through leasing. We’ve never issued equity or anything to acquire all of the long-term onshore assets that we have. Tough or no different. We feel at a macro level that with our relationships to all the partners of LNG Canada that we’re uniquely represented there, and we see that LNG coming off the West Coast is going to be a key and we see that expanding from a macro perspective, differentiated situation as to our forward sales. We’re also very happy about the limited forward sales we’ve done so far, which shows there’s a market for higher gas out there.

And then we see a lot of action in the Duvernay Shale today, a lot of M&A, big significant sale by Chevron. These assets are very valuable, very sought after over the long haul, and it gives us that peak in the LNG globally coming off the West Coast of Canada one day with a large position, but both Eric and Tom and I lived and worked in Malaysia. We’re the only player there with international experience that are known by all the partners of LNG Canada uniquely well and a visit to Southeast Asia recently where we get all the meetings there. So, we’re different up there, and I believe that should frame it for you unless you need more detail from Eric which you’d be glad to provide.

Tom Mireles: Yeah. Thanks. Roger, I’ll just make a couple more observations. What we’ve done with our Tupper Montney asset over the last five or six years is really turn it into one of the most capital efficient North America dry gas assets in terms of our ability to develop resource at a low cost. We’ve done a tremendous job with our well cost and our well performance. We have some of the leading wells in Western Canada from an IP30 perspective. So, we’re controlling what we can, which is the capital efficiency of our opportunities there. And unfortunately, the current AECO price is quite low, which we think will improve over time. If you look long term, we believe gas and natural gas in Western Canada and LNG will continue to be a really pivotal part of energy future.

And we feel well positioned on that from a geography perspective as Roger pointed out and also a cost perspective. We’ll be the go to gas because we have the most capital efficiency. One other comment I’ll make around our Canada portfolio is in our [Indiscernible], which we entered in 2016, we have proven that we have quite a nice asset there with nearly 500 locations to invest in. It’s a very oily position in the KaBOB. We really have well performing, top industry performing on an oil rate basis wells in KaBOB and it will allow us to invest there when ultimately our Eagle Ford locations start to move past their top tier, we’ll be able to pivot our investment into the KaBOB and that will allow us with the assets in our portfolio now to maintain a high oil weighting, high cash flow generating shale business for multiple decades.

Unidentified Analyst: That’s very helpful. Thank you so much. And I just have a quick follow-up on the outlook for incremental efficiencies from here. Kind of recognizing the progress thus far that you’ve highlighted so far in the call and then on the Eagle Ford, for example, on Slide 10, what are the additional untapped levers that you think can further drive efficiencies over time? Thank you.

Roger Jenkins: That’s a great question. So, one of the things I wanted to highlight and one of the reasons why we prepared the slide like we did for our earnings call was you commonly have fluctuation in service costs, which, of course, we’re anticipating a little bit of a reduction in pressure pumping and rig costs next year compared to this year for our Eagle Ford business. But that’s really not what’s driving our performance here. Our performance is driven by the fact that we’re able to improve consistently our operations, how we set up on location, how we pump our fracs, how we design and drill our wells, and, how we optimize our completions in real time. That’s allowing us to get more efficient from a pumping hours perspective so we bring online wells slightly cheaper and sooner, which is critical and also, recognizing the lowest cost or lateral foot we’ve achieved in our Eagle Ford business in the history of the play, which I think is a great accomplishment by my team, and I’m extremely proud of that.

We consistently look for more opportunities. It’s hard for me to know exactly what the next thing my team will come up with in terms to of improving efficiency. But we’ve demonstrated a strong track record of continuing to improve operations for many years, and I anticipate they’ll keep looking for the same.

Unidentified Analyst: Very helpful. Thank you.

Operator: Thank you. [Operator Instructions]. Your next question comes from Paul Cheng with Scotiabank. Please go ahead.

Paul Cheng: Hey, good morning guys.

Roger Jenkins: Good morning, Paul.

Paul Cheng: What I just want to say congratulations for the retirement and thank you for all the help and insight. And also, sorry, sometime I lost very intelligent questions. So, we now appreciate. And Eric, congratulation for the promotion and look forward to working with you.

Eric Hambly : They were good questions. I just didn’t like them all, but they were not unintelligent questions as I recall.

Paul Cheng: Thank you. Two questions. I think the first one maybe either to one of you gentlemen. Third quarter year to date, your buyback certainly has been great and significantly above the 50% adjusted free cash flow rate. And so, in a sense, understandable given the stock where you are. If we’re looking at over the next, say, several quarter given the uncertainty in the oil market, how should we look at your buyback rate? Is it going to be closer to the 50% adjusted free cash flow as you stay in your Murphy’s 3.0? Or that is going to be significantly above yet closer to what we have seen year to date? That’s the first question.

Eric Hambly : Paul, it’s hard to predict that plus we have a Board of Directors that we keep informed. We’re closely working with our Board and our Finance Committee on our financial outcomes. Tom and his team, Lester and Treasury does a lot of detail around where the free cash flow will go and what will happen. I will say that from a debt perspective, we didn’t I didn’t personally feel that we’re getting paid for all the debt reduction. I think it’s greatly helped the company a lot. And we also think when we have little bit more than $1 billion right now, we had incredible outgo of our bonds. I mean, we were so oversubscribed for our bonds, it was incredible. So, and then our new revolving credit facility, a 50% increase in our revolving credit facility unsecured on a non-investment grade company.

So, our balance sheet is greatly regarded. And when you’re in the low 30s like this, you got to be thinking more than the minimum 50%. And we’re so undervalued as to oil price today, long term low oil price that until the stock gets up into the 40s, you got to be thinking more than 50 on the other way. But Eric and Tom will work that and manage that and so our board and our finance committee. And we, of course, want to pay down a little bit of debt at the end of the year as per our agreement on these notes. But got to be thinking more than 50 if the equity stays at this level, quite honestly, Paul.

Paul Cheng: Yeah. Because, I mean, you can actually paying out more than a 100%. So is that a reasonable level that we could assume, over the next…

Roger Jenkins: I don’t think I don’t think Tom likes to go more than a 100. He likes to use some cash available, but they are dislocation situations where we would, put on balance sheet if we start hanging around these low thirties because it’s just too undervalued. But that’s getting ahead of it. We, have a lot of different risk factors in the business. One was clipped off this week, still have unrest in the Middle East and what will happen with the Fed. So, several things we have to monitor and evaluate as Eric says, but can’t go over a 100 forever, Paul. So, but we got to be looking at the 50 plus right now. But we shall see, as you know. But we’re focused on shareholders here. One of the things I’m really proud of my career is a lot of money paid for dividends, long history of paying dividend, looking to put our board approval hopefully to increase our dividend next year, continue to buy back stock and execute and work forward with big potential in both Cote D’ivoire and Vietnam.

And we’ve got a lot of things heading our way. There’ll be little quarterly things here and there, but over the long haul, looking really good shape as to rewarding shareholders here at Murphy Oil.

Paul Cheng: Thank you. The same question I think is for Eric. Eric, I mean, this year Gulf of Mexico have far higher than usual workover. At the beginning of the year, we already know that it’s the case. But look like, yes, even heavier than what we would have expected. Like, for example, fourth quarter the two well going to be in workover. Typically, I don’t think it’s on the schedule. So, is it just purely unlucky or that something is happening and need to be maybe adjusted in your process? Thank you.

Eric Hambly : Great question. It is purely unlucky, and I really wish my luck was better because it’s been a challenging year for us with lost revenue and additional workover expenses. As I mentioned earlier on responses to the call, it’s not common that we have this type of thing happen with a well or wells. And it’s been a challenging year with a bit of not very lucky. And as you pointed out at the beginning of the year, we didn’t have these fourth quarter workovers on our horizon. So, yeah, happy to see the back of it in early 2025 when we finish these two workovers.

Paul Cheng: All right. Very good. Thank you.

Eric Hambly : Thank you, Paul. Appreciate it.

Operator: Your next question comes from Tim Rezvan with KeyBanc. Please go ahead.

Roger Jenkins: Good morning, Tim.

Tim Rezvan: Good morning, folks. Good morning. Thanks for taking my questions, and congratulations, folks, on the, retirement and promotion.

Roger Jenkins: Thanks, Tim.

Tim Rezvan: I was hoping to dig back into the Eagle Ford, a little bit. I’m trying to understand your comments about a more consistent onshore rig schedule. Does that imply a full-time rig year-round? I know you’ve been intermittent in the past. So, what does kind of more consistent need? So, we’re just trying to understand if this is just accelerated TILs in 2025 or a real sort of structural change in how you view developing the asset? Thank you.

Roger Jenkins: Yeah, Tim. Thanks for that. That gives me an opportunity to clarify. In 2021 through 2023, we typically ran a two-rig program for the first half of the year. So, we delivered drilled almost all of our wells in the first half of the year and then delivered them. We pivoted in ‘24 to have one rig running consistently all year long and anticipate doing that going forward. It should smooth out our well delivery cadence a little bit. We’ll be a little less peaky throughout the year. Hopefully, we’ll make people like you a little happier with our consistency.

Tim Rezvan: Okay. I appreciate the clarification. Happier.

Roger Jenkins: I think it’s accurate in general.

Tim Rezvan: Yeah. And then as a follow-up, just touching back on the LNG Canada, the macro story up there. The comments on that plant coming online on schedule have been generally positive. So, what would you need to see from LNG Canada, and when would you need to see that to start really thinking hard about it expanding your plan in the Montney and growing production there? Thank you.

Roger Jenkins: I’ll let Eric answer that because I won’t be here for that.

Eric Hambly : Yeah. Okay. Well, it gives me a chance to frame it a little bit. So, the first phase of development for LNG Canada, the gas as we understand it, that’ll feed that has been provided from predominantly from people who own an interest in the plant. So, they’re sourcing their own gas. The opportunity that we see is more likely to participate in a Phase 2, which we think is likely probably get approved sometime in the next three or four years. And, that would that would be another approximately 2 BCF a day of takeaway of gas out of Western Canada. So just the fact that that second phase moves forward will be, I think, quite good for the overall AECO market. We also, as Roger was attempting to highlight, we have likely an opportunity to work with these people that we know and operate with in Asia who may decide that some of the gas for the Phase 2 could come from our asset, Tupper Montney, instead of gas they would develop themselves.

And so that’s an opportunity that we will monitor. We’ll consider, if the type of deal that we think would be accretive is available, then we may pursue it as part of a diversification strategy. So, going back and looking at our overall Montney diversification, we’ve done fixed forward sales. We’ve done diverse sales into the U.S. markets. We would then consider some of our gas being sold in LNG Canada as part of a diversification strategy. LNG prices globally can swing around quite a bit, and they’re not immune to price fluctuations. So, we wouldn’t want to dedicate all of our gas to an LNG, especially one LNG plant. So, it’s part of the overall strategy there. We that’s kind of how we think about it. And, just a little more color on longer term.

If we decided to expand the plant capacity beyond its current 500 million cubic feet per day, it would be an approximately three-year process from a engineering and a permitting approval perspective. In construction, it’s about a three-year process. So, if we were to do that, we would definitely signal well in advance we would be doing that. You would know about it for several years before we were able to materially deliver more gas from our asset.

Tim Rezvan: Okay. I appreciate the high-level detail. Thank you.

Operator: Your next question comes from Arun Jayaram. Please go ahead.

Arun Jayaram: Yeah. Good morning, gentlemen. Roger, I wanted to wish you the best as you head off into the sunset. Hopefully, you’ll be at Tiger Stadium this weekend as well.

Roger Jenkins: I’ll be there with a 104,000 other friends.

Arun Jayaram: Good luck this weekend. I will also be at, in Austin for playing the Gators. But, anyways, I probably shouldn’t talk too much about college football here. That’s right. Although I could spend a lot of time talking about it. Well, anyways, best to you and Eric. Good luck filling Roger’s large shoes as you take over as CEO early next year. Quick question, Roger, on the regulatory environment in the Gulf of Mexico. Obviously, the market is a little bit worried around the buy up and that process and I think that’s been punted a little bit. But just maybe you or Eric could comment on your thoughts on the regulatory environment in Gulf of Mexico, obviously, with the new administration and thoughts around just your ability to execute your program from a permit procurement perspective?

Roger Jenkins: I’ll just take a quick stab, but, obviously, we’ve had a lot we’ve had change in the Gulf of Mexico regulatory in two phases. One, post Macondo, a lot of BOP regulatory, a lot of different change in welds on, a lot more interaction. One thing people may not realize, the Gulf of Mexico has been heavily regulated my entire 40 plus year career. A lot of information, a lot of monitoring, a lot of inspection. So, the federal government through the Department of Interior has monitored Gulf of Mexico, federal leases in an incredible detailed way for my entire career. Macondo kicked it on up a notch, and then this administration we have in office today did an all-out effort to eliminate and try to stop lease sales in the Gulf of Mexico, also more scrutiny around awarding the blocks.

I anticipate that to change and change extremely quickly. This time because of the Republican Senate that will allow the changes in department tier that’s needed to help the industry thrive. Again, I always personally thought the buy up is a big old joke thing. It’s another example of nothing at all, never you mind thing, too big to fail thing. It’s extended into May, which is positive, but then we’ll have to redo a day that while I’m from fisheries. We’ll have to redo this. I anticipate this to move forward without any issue in any way. I have no concern about it as a shareholder of Murphy in any way. And those type of things will calm down with the new administration and we look forward to moving forward with that because it probably helps us a good bit in the U.S. Department of Interior regulated Gulf of Mexico with this administration change.

So, if Eric wants to add some color to how to set it up for you as buy up, not a thing, Eric.

Eric Hambly : Excellent. You can disagree. I totally agree. We’ve we have been communicating consistently, that we did not expect to snip an issue from this or really an issue at all. We were very happy to see the recent ruling, which pushed out the biologic opinion, the data which should be vacated into May, as Roger pointed out. We expected that. And, but I wanted to make another point in which is even if that had not happened or if there’s some delay in that being in place in May or some type of related issue to the biological being in question. We do not believe it will impact our operations. Our current operations and production are not impacted by this at all. We also the way we view the permitting process and understand how the biological opinion works, industry agencies would still be able to approve permits for our proposed operations.

It might just take a little bit longer. The a biological opinion allows for that seem to have a streamlined process because they didn’t have to consider the impact that every single proposed operation may have on endangered species. So, it’s sort of a blanket approval. They, without the Kaybob in place, they would still be able to approve permits and allow our operations to proceed. It might just take a little longer because they would have to review every permit that’s applied for on the basis of how it impacted endangered species. So, they may not like it, but they can do that and that’s how we expect that. And just reiterating, we don’t expect any issue in the near term or next year on our current operations at all.

Arun Jayaram: Great. Thanks for that. My follow-up, Roger and Eric, I moonlight as JPMorgan’s oilfield service analyst as well. Unfortunately, I don’t get paid by the hour.

Roger Jenkins: We see that. We love reading that.

Arun Viswanathan : Okay. Unfortunately, Roger, I don’t get paid by the hour. But one thing I did note is I follow [Indiscernible]. And interestingly, they put, the Murphy Pay one project on their subsea opportunity list. And so just wanted to get if you can maybe describe maybe where that project’s at. I assume that Doug and his team wouldn’t put that on the list unless they thought that there’s a good chance that this would occur. So, thought that was kind of an interesting data point from the Tech Leap FMC slide deck.

Roger Jenkins: Thank you, Arun. I know Doug extremely well. We’re the same age. We’ve been worked together for over 40 years. Really appreciate him doing that. I’ll have to text him about that. Great guy, by the way. I’ll let Eric’s really close to pawn, and we’re working on it, obviously, as per our required field development plan, but I’ll let him move forward on that.

Eric Hambly : Yeah. Thanks. We are making rapid progress on our preparation of a field development plan for that pond discovered resource. The commitment we have under our block is to submit a field development plan by the end of 2025. Well, we’re on track to do that by the end of 2024. So, as we’ve been progressing our evaluation there, we’re doing several things. In parallel, addressing the subsurface to make sure we understand the resource completely, going out and doing engineering studies around how we would develop the field with an FPSO and the subsea infrastructure that technique FMC highlighted. And also negotiating with various Ivorian parties around the, the price that we would sell gas or the structure around how we would sell gas in the country.

All of which are critical for the project moving forward. We’ve been aggressive in moving this forward because we think it’s an opportunity that would be very material and nice for us. And also, the country of code of law really needs the gas, to feed power plants that they have with a declining domestic gas supply. We think PON has an opportunity to provide that and really help the country and be a mutually beneficial project for us, service providers and also the Ivorians. So, we’re moving all of that. We have not awarded any contracts to do, for fabrication or installation of any facilities. We have not sanctioned the project. But there are a limited number of subsea providers. And as you can imagine, we’re in conversation with a limited number of providers that would do that type of work.

And so, it’s not unreasonable to think if we did move the project forward with a future sanction date that they might be in play.

Arun Jayaram: Got it. Got it. And just maybe a follow-up on that, Eric. Would that project be included in your medium-term CapEx guide of $1.1 billion or would that be kind of a project that would be discrete and on top of that?

Eric Hambly : It’s not included in our $1.1 billion three-year average CapEx. It’d be something on top of that.

Arun Jayaram: Okay. That’s helpful.

Eric Hambly : I would not anticipate material spend in that three-year period related to PON. There’d be minimal spend related to engineering and some long lead commitments if we were to sanction the project, say, as early as next year.

Arun Jayaram: Okay. Great. Thanks a lot, gentlemen. Again, Roger, best to you.

Roger Jenkins: Thanks, Arun. Appreciate it.

Operator: There are no further questions from our phone lines. I would now like to turn the call back over to Roger Jenkins for any closing remarks.

Roger Jenkins : No closing remarks. Had a great call today, and, appreciate everyone calling in. A lot of good questions today, and next call will be in late January, and Eric will be sitting in this chair. I wish him all the best. And we’ll move on from there. We appreciate it. Thank you all.

Eric Hambly : Thank you.

Operator: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you disconnect your lines.