Murphy Oil Q3 2024 Earnings Call Transcript

Quartr
Provided by Quartr
November 7, 2024

There are 12 speakers on the call.

Operator

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2024 Earnings Conference Call and Webcast. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Speaker 1

Good morning, everyone, and thank you for joining us on our Q3 earnings call today. With me are Roger Jenkins, Chief Executive Officer Eric Hambly, President and Chief Operating Officer and Tom Morales, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we've placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude our non controlling interest in the Gulf of Mexico. Slide 2.

Speaker 1

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 the results to differ. For further discussion of risk factors, see Murphy's 2023 Annual Report on Form 10 ks on file with the SEC. Murphy takes no duty to publicly update or revise any forward looking statements.

Speaker 1

I will now turn the call over to Roger Jenkins. Roger?

Speaker 2

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 Q3, 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 Q3.

Speaker 2

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 Q4, we initiated construction of the Loc Duvang production platform for our field development project in Vietnam. Also in the Q3, we began drilling the Siu Vang or HSV exploration well, which initiated our 2 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 Q3, we repurchased $194,000,000 of stock or 5,400,000 shares.

Speaker 2

Year to date, Murphy has repurchased $300,000,000 of stock or 8,000,000 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 move 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. I 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.

Speaker 2

Most significantly year to date, we returned 110 percent 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 $1,000,000,000 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 2 years ago. Since that time, we've repurchased $450,000,000 of shares and increased our dividend by 70%.

Speaker 2

As of November 5, we have approximately $650,000,000 remaining under our approved $1,100,000,000 total share repurchase authorization. On Slide 5, Murphy produced an average of 185,000 barrels equivalent in the Q3 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 our realized NGL price was nearly $22 and natural gas was $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 $700,000,000 of revenue in the quarter excluding our non controlling interest.

Speaker 2

I'm now going to turn the call over to our CFO, Tom Morales, for an update on financial results. Tom?

Speaker 3

Thank you, Roger. Good morning, everyone. Slide 6. Murphy reported net income of $139,000,000 in the 3rd quarter or $0.93 per diluted share and adjusted net income of $111,000,000 or $0.74 per diluted share. Overall, we generated $397,000,000 of adjusted EBITDA during the quarter with $211,000,000 of accrued CapEx excluding non controlling interest.

Speaker 3

As a result of the free cash flow generated during the quarter, we were able to repurchase nearly $200,000,000 of stock at an average price of just over $36 per share. Year to date, we have repurchased $300,000,000 of stock and reduced $50,000,000 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 Q4 with extending our debt maturity profile through the issuance of senior notes due 2,032 and the partial tender of notes due 2027, 2028, and 2029.

Speaker 3

We plan to call the remaining $79,000,000 of senior notes in the Q4 so that the transactions are debt neutral. Additionally, we entered into a new 5 year $1,200,000,000 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 $400,000,000 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.

Speaker 3

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 Hambley, our President and Chief Operating Officer to discuss our operational updates.

Speaker 4

Thank you, Tom. Slide 10. In the Eagle Ford Shale, Murphy produced an average 32,000 barrels of oil equivalent per day in the Q3 with 72% oil and 86% liquids volumes. We continue 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 4th quarter with 4 planned to come online in Catarina as well as drilling 8 Karnes wells to hold as DUCs in advance of 2025 completions.

Speaker 4

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.

Speaker 4

Murphy produced an average 429,000,000 net cubic feet per day in the 3rd quarter from our Tupper Montney asset, which exceeded guidance by approximately 11,000,000 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 Q3 this accounted for nearly half of volume sold. Murphy also sold significant volumes at diverse price points including Malin, Ventura, Emerson, Chicago and Don. 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.

Speaker 4

Slide 12. The Gulf of Mexico, Murphy produced an average 67,000 barrels of oil equivalent per day with 79% oil in the 3rd quarter. We brought online the operated Mooremont No. 3 well and spud Mooremont No. 4 as planned in the quarter.

Speaker 4

And I'm excited at the initial results from drilling this new well. Additionally, I'm pleased with the results of our 2 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 St. Malo Waterflood Project during the quarter. Recently, we started our 1st Murphy operated ocean bottom node seismic survey across the Khaleesi, Mormont and Samurai fields and the nearby prospects.

Speaker 4

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 Q3, non operated Terra Nova production was impacted by additional downtime. As we previously announced, we brought online all planned workovers during the Q3 for $34,000,000 of total workover expenses. For the Q4, we forecast $40,000,000 of workover expenses at the operated Samurai No. 3 and Marmalade No.

Speaker 4

3 wells. We recently developed a mechanical issue at the operated Samurai No. 3 well 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 Lok Davang.

Speaker 4

We achieved a significant milestone early in the Q4 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 1st oil in late 2026. Slide 15.

Speaker 4

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 Suvang 1X exploration well in Block 15 to 17 in Q3.

Speaker 4

After drilling this well, the rig will move to drill the Loke de Hong 1X exploration well in Block 15105 in the Q4. We forecast $30,000,000 in total net drilling costs for the 2 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.

Speaker 4

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 will begin likely begin planning for 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 Q4, we forecast production of 181,500 barrels to 189,500 barrels of oil equivalent per day with 51% oil volumes and 56% liquid volumes.

Speaker 4

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 Q4 forecast also includes planned accrued CapEx of $203,000,000 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 percent liquids volumes. As previously disclosed, production has been impacted by continued downtime at Terra Nova. We are maintaining our accrued CapEx range of $920,000,000 to $1,020,000,000 excluding NCI. Slide 20.

Speaker 4

We share our multi year 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 Q4 results in January. However, many aspects will remain constant. As we look toward the future, Murphy remains committed to our $1,000,000,000 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.

Speaker 4

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 Code of Bois. 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.

Speaker 2

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 Q4. Moreover, we're advancing our Vietnam development and exploration plans and we look forward to expanding our portfolio with high impact exploration opportunities.

Speaker 2

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 guessing one along the way. I'd like to thank all our analysts that covered us all these years. I'd also like to personally thank Kelly Whitley for leading our IR efforts over the last 9 years.

Speaker 2

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. I'd also like to thank our shareholders for their support of my 11 year plus career as CEO. I wish Eric all the best.

Speaker 2

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 all.

Operator

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

Speaker 5

Good morning, guys. And first, Roger, I want to congratulate you on the retirement Eric on the appointment. Roger has been down. Really appreciate all your help along the way. But again, congratulations.

Speaker 5

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 prices do and I'm just wondering depending on 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?

Speaker 4

Neil, this is Eric. I'll jump in and answer the question. The way we think about our program, we've communicated in the past that our aspiration for our company from 2024 through 20 6 is to have oil weighted low CAGR growth while spending approximately $1,100,000,000 of CapEx on average annual basis. We remain committed to that plan. If you look to 2025, I would anticipate production in 2025 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.

Speaker 4

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.

Speaker 5

Love the optionality. Thanks, Eric. And then just second question on Vietnam. I'm just wondering 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 wanted have you all spoken about plans in Vietnam beyond these first U. S.

Speaker 5

Formation wells?

Speaker 4

Great question, Neil. We're really excited about our Vietnam progress here. We made a really nice discovery that we're developing in the Lotte Van field, which is 100,000,000 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 Q3 on the first of 2 prospects.

Speaker 4

The Hai Sibang prospect is targeting a mean of 170,000,000 barrel oil equivalent to upward of over 400,000,000 barrels, which is a really nice sizable prospect. If you compare that to the 100,000,000 barrel Lactavang field, obviously it's something that we're really excited about. It has a potential to be really material. After we drill the Hai Sivong well, we'll move to the Lok Tahong and that targets a 65,000,000 barrel mean to 135,000,000 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.

Speaker 4

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.

Speaker 2

Just a bit more color on that, Neil. 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 Malaysia and 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 1 and development on the other, very unique, very changeable for our company and really good sets of business that was put together here by our team.

Speaker 4

Just last comment for me, Neil, 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. Thank you both.

Operator

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

Speaker 6

Good morning, Carlos. Hey, good morning, guys. Good morning. First of all, Roger, Congratulations on the role as well. Roger, I think Alabama might win this weekend.

Speaker 6

So, hey, this is Paul, your retirement. Hey, Vega.

Speaker 7

Oh, wow. I thought

Speaker 2

you're way too smart for that honestly.

Speaker 6

Oh, boy. 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.

Speaker 6

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?

Speaker 2

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 allocation 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.

Speaker 2

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.

Speaker 2

And I will say that in both Cote D'ivoire and Vietnam, we're incredibly welcome there by these governments. They're very happy to have a company like Murphy with super major execution ability, which we all worked at super majors. That's what we built here at Murphy. So we're really advantaged in any kind of thing, but 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.

Speaker 4

Yes. 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 breakevens, most of them below $35 a barrel. In our onshore, we have an extensive shale oil inventory of locations, 1200 locations in Eagle Ford, nearly 500 locations in the Kaibab Duvernay 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.

Speaker 4

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.

Speaker 4

You did ask a question about consolidation and I wasn't quite sure how you frame that and maybe you could re ask that. I can help answer that question for you.

Speaker 6

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.

Speaker 6

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?

Speaker 4

Okay. Yes, 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 and A across the space, primarily in the offshore where we think we have a competitive advantage.

Speaker 4

We have proven over the last decade to be very active with successful M and A, made really nice divestiture in Malaysia 2019, made great acquisitions in 2018 2019 in the Gulf of Mexico, built a very nice deepwater Gulf of Mexico position, partly through successful exploration and partly through M and 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.

Speaker 4

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 band, but we're always watching to see what we can find that may be advantaged from a to us from an inorganic perspective.

Speaker 6

Sure, 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.

Speaker 6

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?

Speaker 4

Yes. So we're at 18% working interest on Terra Nova. We've been extremely disappointed with the performance of the asset from a runtime perspective. You contrast how we do in our operated assets. For example, in Kings Key, we produced that asset with a 98% uptime.

Speaker 4

Terra Nova has been averaging about a 55% uptime. We expected that they would be 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.

Speaker 4

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 4th 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.

Speaker 4

And there's no language in the operating agreement where that would become 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.

Speaker 6

Got you. Thank you, guys. Congrats again.

Operator

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

Speaker 8

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 Q4. 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've kind of had in the past.

Speaker 8

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 Q4 drilling and just get after the onshore in general a little bit earlier in the year to smooth it out?

Speaker 4

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.

Speaker 4

We are drilling wells in the Q4 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 3000 or 4000 barrels a day on an annual average basis in 2025 compared to 2024. For onshore Canada and specifically in our Tupper asset, we expect to get to work drilling the 1st pad in the last month of the year. That's been sort of normal for us over the last few years.

Speaker 4

We have a very limited program required in that tougher 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 delivery of our new wells.

Speaker 4

Hope that helped frame what we're trying to do with our onshore assets for you.

Speaker 8

That's helpful for sure. And I just wanted to touch a little bit on workover expenses.

Speaker 4

Looks like they're going

Speaker 8

to be up a little bit in 4Q versus 3Q. And I think you detailed some of that in your prepared comments with 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.

Speaker 8

Can you just provide a little bit more perspective around that?

Speaker 4

Yes. 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 Q3, we were able to complete the workovers that we anticipate at the time, primarily toward the early part of Q3. So our workover expense was a little bit lower.

Speaker 4

As we're heading into the Q4, 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 Marmalade 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.

Speaker 4

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.

Speaker 1

Okay. Thanks.

Operator

Thank you. Your next question comes from Greta Drifff at Goldman Sachs. Please go ahead.

Speaker 9

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.

Speaker 7

I'll let Eric

Speaker 2

answer that question. But first, I have to frame that. We've been in Canada for probably almost 70 years. We're a very known operator there. We have a very unique position in the Montney we built from scratch through leasing.

Speaker 2

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 and A, big significant sale by Chevron. These assets are very valuable, very sought after over the long haul.

Speaker 2

And it gives us that peak into 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. Yes, thanks.

Speaker 2

Roger, I'll just make a

Speaker 4

couple more observations. What we've done with our Tupper Montney asset over the last 5 or 6 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.

Speaker 4

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 Kaybob Duvernay, which we entered in 2016, we have proven that we have quite a nice asset there with nearly 500 locations to invest in.

Speaker 4

It's a very oily position in the Kaebob. 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.

Speaker 9

That's very helpful. Thank you so much. And then I just have a quick follow-up on the outlook for incremental efficiencies from here, recognizing the progress thus far that you've highlighted so far on 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.

Speaker 4

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.

Speaker 4

So we bring online wells slightly cheaper and sooner, which is critical. And also, recognizing the lowest cost per 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 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.

Speaker 9

Very helpful. Thank you.

Operator

Thank you. Your next question comes from Paul Cheng with Scotiabank. Please go ahead.

Speaker 7

Hey, good morning guys.

Speaker 6

Good morning, Paul.

Speaker 7

Roger, just want to say congratulations for the retirement and thank you for all the help and insight. And also Tori, sometime I'll launch very intelligent questions. So we appreciate. And Eric, congratulation for the promotion and look forward to working with you.

Speaker 2

They were good questions. I just didn't like them all, but they were not unintelligent questions, if I recall.

Speaker 7

Thank you. Two questions. I think the first one maybe either to one of you gentlemen. Q3 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.

Speaker 7

If we're looking at over the next, say, several quarters, 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.

Speaker 2

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.

Speaker 2

And we also think when we have the little bit more than $1,000,000,000 right now, we had incredible outgo of our bonds. I mean, we were so oversubscribed for our bonds. It was incredible. So, and in our new revolving credit facility, a 50% increase and our revolving credit facility unsecured on a non investment grade company. So our balance sheet is greatly regarded.

Speaker 2

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.

Speaker 7

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

Speaker 2

don't think Tom likes to go more than $100,000,000 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 30s 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.

Speaker 2

So several things we have to monitor and evaluate, as Eric says, but can't go over 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 with 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.

Speaker 2

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

Speaker 7

Thank you. The same question, I think, is for Eric. Eric, I mean, this year ago, Mexico have far higher than usual workover. At the beginning of the year, we already know that it's the case. It looks like it's even heavier than what we would have expected.

Speaker 7

Like for example, Q4, the 2 well going to be in workover. Previously, I don't think it's on the schedule. So is it just purely unlucky or that there's something that's happening and need to be maybe adjust in your process? Thank you.

Speaker 4

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 Q4 workovers on our horizon. So, yes, happy to see the back of it in early 2025 when we finish these two workovers.

Speaker 7

All right. We do. Thank you.

Speaker 2

Thank you, Paul. Appreciate

Operator

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

Speaker 10

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

Speaker 1

Thanks, Tim.

Speaker 7

I was

Speaker 10

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 mean?

Speaker 10

So we're just trying to understand if this is just accelerated pills in 2025 or a real sort of structural change in how you view developing the asset? Thank you.

Speaker 4

Yes, Tim. Thanks for that. It gives me an opportunity to clarify. In 2021 through 2023, we typically ran a 2 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.

Speaker 4

We pivoted in 'twenty four to have 1 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.

Speaker 10

Okay. Okay. I appreciate the

Speaker 6

clarification. I think it's Thank Tim Sachs in general.

Speaker 10

Yes. 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?

Speaker 10

Thank you.

Speaker 2

I'll let Aaron answer that because I won't be here for that.

Speaker 4

Yes. 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 will feed that is been provided from predominantly from people who own an interest in the plant. So they're sourcing their own gas.

Speaker 4

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 3 or 4 years. And 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 within 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.

Speaker 4

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.

Speaker 4

LNG prices globally can swing around quite a bit. They're not immune price fluctuations. So we wouldn't want to dedicate all of our gas to LNG, especially 1 LNG plant. So it's part of the overall strategy there. That's kind of how we think about it.

Speaker 4

And just a little more color on longer term, if we decided to expand the plant capacity beyond its current 500,000,000 cubic feet per day, it would be an approximately 3 year process from an engineering and a permitting approval perspective and construction, it's about a 3 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.

Speaker 10

Okay. I appreciate the high level detail. Thank you.

Operator

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

Speaker 11

Yes. 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 for a big one.

Speaker 2

I'll be there with 104,000 other friends.

Speaker 11

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. Although I could spend a lot of time talking about it. Yeah.

Speaker 7

Yeah. I feel.

Speaker 11

Yes. 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 was a little bit worried around the buy up and that process and I think that's been punted a little bit.

Speaker 11

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?

Speaker 2

I'll just take a quick stab. And obviously, we've had a lot we've had change in the Gulf of Mexico regulatory in 2 phases. 1, post Macondo, a lot of BOP regulatory, a lot of different change in well design, 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, is monitored Gulf of Mexico.

Speaker 2

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.

Speaker 2

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 African fisheries will have to redo this. I anticipate this to move forward without any issue in any way. I have no concern about as a shareholder of Murphy in any way. And those type things will calm down with the new administration and we look forward to moving forward with that because it's probably helps us a good bid in the U.

Speaker 2

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 a buy up, not a thing, Eric.

Speaker 3

So, you can disagree. Totally agree. We have been

Speaker 4

communicating consistently that we did not expect a significant 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, 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.

Speaker 4

It might just take a little bit longer. The biological opinion allows for Vese 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. Without the biop 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.

Speaker 4

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.

Speaker 11

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.

Speaker 2

Yes, we see that. We love reading that.

Speaker 11

Okay. Unfortunately, Roger, I don't get paid by the hour. But one thing I did note is I follow TechnipFMC. And interestingly, they put the Murphy Payone project on their subsea opportunity list. And so just wanted to get if you can maybe describe maybe where that project's at.

Speaker 11

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 I thought that was kind of an interesting data point from the TechneFMC

Speaker 2

slide deck. Thank you, Arun. I know Doug extremely well. We're the same age. We've been worked together for over 40 years.

Speaker 2

I really appreciate him doing that. I'll have to text him about that. Great guy, by

Speaker 6

the way.

Speaker 2

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.

Speaker 4

Yes, 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. 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.

Speaker 4

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 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 will be very material and nice for us. And also the country of Cote d'Ivoire 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 Iberians. So we're moving all of that.

Speaker 4

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.

Speaker 11

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 $1,100,000,000 or would that be kind of a project that would be discrete on top of that?

Speaker 4

It's not included in our $1,100,000,000 3 year average CapEx. It'd be something on top of that.

Speaker 11

Okay. I would highlight that

Speaker 4

I would not anticipate material spend in that 3 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.

Speaker 11

Okay, great. Thanks a lot gentlemen. Again, Roger, best to you.

Speaker 2

Thanks, Sabrina. 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.

Speaker 2

No closing remarks. Had a great call today and appreciate everyone calling in. All 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.

Speaker 2

We appreciate it. Thank you all. 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.

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Earnings Conference Call
Murphy Oil Q3 2024
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