Q2 2025 Murphy Oil Corp Earnings Call

August 7, 2025

Assistance, Please press star zero for the operator.

Oh, no nitrogen preference over to Kyle <unk> manager Investor Relations. Please go ahead.

Thank you operator, and welcome everyone to our second quarter 2025 earnings Conference call yesterday. After the close we issued a press release slide presentation, and our quarterly stockholder update which we will reference on today's call. These documents can be found on our website at Murphy oil Corp. Dot Com joining me on todays call are Eric.

<unk>, President and CEO, Tom or al as EVP, and CFO and Chris Lorena SVP operations.

As a reminder, today's call will contain forward looking statements as defined in the private Securities Litigation Reform Act of 1095 as such no assurances can be given that these events will occur or that the projections will be attained a variety of factors exist that may cause actual results to differ.

Further discussion of risk factors. Please refer to Murphy's 2024 annual report on Form 10-K on file with the SEC Murphy takes no duty to publicly update or revise any forward looking statements throughout today's call production numbers reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of America.

Eric will kick off the call with opening remarks, and then we will move to a question and answer session. We ask that you limit yourselves to one question and a follow up with that I will now turn the call over to Eric.

Thanks, Carl and good morning to everyone joining us on the call as Kyle mentioned, we released a new quarterly stockholder update last night in conjunction with our earnings release. This new format shares additional insights and leadership perspectives on our business, which we believe provides a deeper understanding of Murphy to our stockholders.

I hope that everyone had the opportunity to read it and found it helpful. I would like to start by thanking our employees for their hard work and dedication in delivering the results that we will discuss on today's call.

Now turning to second quarter results I will emphasize three key takeaways first our second quarter results were underpinned by comprehensive execution across our multi basin portfolio. We delivered a sequential increase in production to 190000 barrels of oil equivalents per day, which was above.

The high end of our guidance on strong new well productivity from our Eagle Ford shale in Tupper Montney assets.

In the Gulf of America, we completed and returned to production the samurai number three workover in the second quarter and early in the third quarter, we completed the Khaleesi number two workover.

These operational results were delivered with strong capital and operating efficiency.

Second quarter Capex of $251 million and total company lease operating expenses of $11 80 per barrel of oil equivalent were both better than quarterly guidance.

Lastly, our 2025 company operated onshore well program is now complete we brought online 10 wells in the Eagle Ford shale and a four well pad and K, Bob Duvernay early in the third quarter.

In the Gulf of America, we completed and returned to production. The samurai number 3, workover in the second quarter and early. In the third quarter, we completed the kesi number 2 workover. These operational results were delivered with strong capital and operating efficiency.

My second key takeaway. This morning is that we remain on track to deliver our 2025 plan with Capex at the midpoint of the annual guidance range and we now see full year production trending at the midpoint of the annual guidance range.

With the majority of the Gulf of America Workover program behind US, we expect operating expenses in the 10 to $12 per barrel per BOE range. During the second half of 2025.

At Murphy, we are laser focused on running the company with a competitive and right sized cost structure. Since 2019, the company has achieved greater than $700 million.

Of cumulative cash cost savings through a greater than 50% reduction in both our G&A and bond interest expenses you can expect us to continue to have a relentless focus on managing our cost structure.

My third and final key takeaway today is looking ahead to our high impact exploration and appraisal activity in the second quarter of the year, our global exploration teams will be exploring and appraising prospects across three different continents testing more than 500 million barrels of oil equivalent to more than 1 billion barrels of oil.

It means to upward gross unrest resource potential. These are key catalysts for the company and we look forward to sharing more results with you in the coming months and with that we can open up the line for Q&A.

Thank you ladies and gentlemen, we will now begin the question and answer session should you have a question. Please press star followed by one or you touched on found Julia Brown that Johan has been rates should do we should the lack of new building prices. Please press star followed by the <unk>.

You're using a speaker phone please lift the handset before pressing any keys.

A moment please for your first question.

Your first question comes from Ireland, <unk> with J P. Morgan. Please go ahead.

Yes, good morning, Eric.

Good morning.

I was wondering if maybe you could highlight.

Or maybe detail the near term exploration program, you mentioned that you'll be testing.

500, mbo kind of resource potential, but maybe set the stage for the key prospects. We did note that you've contracted a transocean rig.

<unk>.

West Africa program, we think it also added some rig time on the noble rig in the Gulf of America.

Sure. It's a great question. Thanks for the opportunity to talk about our program as I've highlighted in my letter in my comments just now we're very excited about our exploration and appraisal program that we have in front of US we're testing some significant volumes and it's really an exciting time at Murphy.

Work through the calendar as we go through the end of the year. So in the third quarter likely in September we will spud our first of two wells in the Gulf of America. The cello number one well in the Mississippi Canyon area, and we'll follow that by the banjo, well, which will be drilled b.

<unk> in the fourth quarter.

In Vietnam, we have a very important appraisal well planned at our highest <unk>, our Golden Sea Lion.

Discovery and that well will likely spud in September some time and we should have a result at some point in the fourth quarter and then wrapping up the year, we should spud in the fourth quarter. The first of our three wells in our <unk> program in West Africa. The first well that we will drill will almost definitely be the sirvente Prost.

Specced, which we've highlighted previously which tests mean over 400 million barrel potential resource on a gross on risk basis pretty exciting times for US you mentioned the rig we did sign a rig contract for that program in code of law. We're very happy that we were able to attract a very high performing rig with experience operating.

<unk> in the region and at what we think is a competitive day rate, which as you know for a deepwater wells it tends to be a significant portion of the well cost.

Yes. Thank you signed it for around 360, which is.

Below where leading edge rates have been so there's a good price on that rig.

The follow up Eric I wanted to talk about kind of your strategy around the Chinook development well, obviously in <unk>, you announced the acquisition of an of the pioneer Fps, So which I believe is in close proximity to the <unk>.

So talk to us about the broader strategy.

Around that maybe set the stage for that <unk>, because I think you have like at 86% working interest in that well.

Yes, that's exactly right. So we were very happy to acquire of the peso. What we think was a very accretive deal for us it allowed us to lower our cost structure in the field and made the future development of the field much more economic and so by itself. It was a good deal, but it really unlocked further development potential.

This is a field that we acquired as part of our Petrobras joint venture deal, we call <unk>, which represents our noncontrolling interest in the Gulf, We did that deal in 2018.

And have been since studying opportunities for enhancing the value of the field and one of the opportunities. We identified was to drill another development well in the currently producing main pay and the Chinook field and we're planning and very likely will include in our 2026 budget to drill a well that we expect to be.

Quite a high rate it should be on the order of 15000 barrels a day and as you have noted our ownership is quite high so the impact to us on a net basis will be significant. So this is a field that's been producing.

There have been two wells producing in the field and in the past. There is currently one so we're targeting an optimally placed additional development well to further develop that field enhance the value and again, it's a very attractive economically.

Very low breakeven as you can imagine based on the rate and the costs, we expect that that well assuming that we do included in our 2026 budget will probably come online in the second half of 2026.

We are working to realize our rig schedule, what's your pre drill on that.

<unk>.

We typically don't describe the opportunity set like that four development wells, but I'll give you roughly I think that it does two things for us the well itself would sort of be what might be sort of a typical wilcox opportunity the well would probably produce in the 20 to 30 million barrels ultimately.

And that it would also help extend the life of the rest of the field. So that might add another say 10 to 20 million barrels of full life potential for the field. So it does create a lot of value allows the field life to go out probably till 2040 or so.

Great I appreciate the stockholder letter really makes our lives easier really really a good way to communicate so thanks for that thanks.

So I'm really glad you appreciate it and I thought it was a nice way to describe our business, which is relatively complex in a fairly simple way. So thanks for your feedback thanks, Mike.

Thank you. Your next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

Yes, good morning team I, just want to start on the Gulf of America It looks like.

Production came in at.

Although higher than the quarterly guide.

Am I right to characterize you guys having worked through some of the operational challenges that we saw earlier this year or is there anything left to derisk.

Yes, Neil Thanks for that I would characterize your observation is accurate.

I'm really happy that the team has worked through what was an unfortunately large backlog of workover activity in the Gulf of America.

We're almost done we are working on the <unk> three well and expect to have that online in August. So that's the last of the significant planned workover activity.

Production did outperform a little bit in the second quarter, which we need as you know our Gulf of American business is quite oily so oil volumes being supported by strong execution, there are quite important to us.

I would say that the workover activities should be wrapped up.

In the third quarter, although we may have sort of proactive workover activity that may be things that we identified to do that or kind of volume adders that haven't been built into our plan in the past those are things we are always evaluating.

But they're not of the reactive type that we've experienced over say the last 18 months and more things we may consider to do to create additional value.

Thank you and then the follow up is just your perspective on return of capital.

Pretty close to your net debt target of around.

The $1 billion and so as.

As you think about prioritizing debt repurchase debt paydown versus further stock repurchases, let's talk about the conversation in the boardroom and where you lean on that.

Neil as I pointed out in my stockholder letter.

We are much more likely to prioritize share repurchase then further debt reduction at this time I would caveat that with we do have $200 million drawn on our unsecured revolving credit facility at the end of the quarter I am not a big fan of having a drawn credit facility. So we may over the course of the next.

Year, or whatever assess paying that down versus share repurchase, but the lower oil price goes the lower our share price will likely go since we trade in tandem with oil price and the more likely we are to repurchase our stock instead of do any type of debt reduction.

Eric.

Sure.

Thank you.

Thank you next question comes from Phillip Jungwirth with BMO capital market. These go ahead.

Thanks, Good morning.

You had some really strong results from the Eagle Ford and specifically Karnes County.

You still have over 300 locations here, so which is quite large relative to the size of the program. So I'm just wondering how de risked you feel like inventory is in with the more intense completions.

Pact that running room at all or do you still feel good about that along with the potentially higher recoveries.

That's a great question.

Let me do two things there one is characterize our overall karnes position and then come back to a more specific a pad that we can talk about as.

As you know and we featured in past calls, we're always trying to improve the performance of our onshore well program and we make adjustments to our completion designs to try to accomplish that as well as our flowback strategies and I was very impressed with our team after not having any karnes wells in 2024, we delivered.

Pretty healthy program of Karnes County wells in the second quarter, we saw some exceptional performance we're seeing.

30% higher performance of the Eagle Ford on a two month cumulative oil basis compared to our past activity and when we benchmark against industry peers, which are some of the top performing wells in Karnes County, and as you know they are quite oily, so really happy that our adjustments to the way that we can drill complete and flow back are showing some strong.

Performance and the team has done a great job.

I'd also like to highlight one additional point and that is one of our five well pads had four lower Eagle Ford Wells and one upper Eagle Ford well that were infill in the sense that they were all drilled around on top of nearby.

Legacy quite long life original Karnes wells and so why that's important is that of our 90 something remaining lower Eagle Ford Wells, then we disclose in the appendix of our slide deck and we referred to.

59 of those are lower Eagle Ford infill wells.

If you look at external data sources like in various they give us no credit for the remaining inventory of those lower Eagle Ford infill wells.

And the wells that we brought online the Turner pad or some of the best performing Karnes Wells, we've had in our history and there were four of those five were lower Eagle Ford infill, which I think gives us even more confidence that what we thought we would be able to extract from the infill program is something that we should have confidence in and also I think something.

That the market should give us some credit for.

Okay, Great and then.

I was hoping you could expand on the Vietnam appraisal well.

Spud here in the third quarter.

What exactly you are looking to test or C.

And at one point Murphy had spoken about wanting Vietnam to be I think a $30 to 50000 barrel a day net business.

I was just wondering if you think you have line of sight here now, including the current development and assuming a successful appraisal.

Yes. Thanks.

Hi, Sue long, our Golden Sea Lion discovery that we made what we've what we've said before was that that well was drilled on significant pay in two different sands most of the pay was in one reservoir.

The primary objective of the appraisal well that we'll spud in September is to test for continuity of reservoir and potentially deeper oil in that main pay reservoir. So the location of the well is designed to test what might be an expanded section of that sand and allow.

US to test very low on structure to see how much of that structure is oilfield specifically located around the development and assessment and appraisal of that specific reservoir, which is the main pay and has the most potential to give us confidence in a significantly larger resource than we've already disclosed so it's really.

Exciting well for us.

The volumes that we've already discovered in the fields that we have in our two blocks in Vietnam give us confidence that we should be able to develop a $30 to 50000 net Boe per day business by the 2000 <unk>.

Obviously with more volume potentially proving up with appraisal of HIFU Vong, we might be at the higher end of that range versus the lower end of that range and Thats really the primary objective of the appraisal well that we're drilling here.

Alright. Thanks.

Thank you.

Paul Cheng Scotiabank. Please go ahead.

Hi.

Morning, guys.

Good morning, Paul.

Maybe the first one is for Tom Tom can you talk.

U S cash tax position going to look like.

Given the new tax enacted beautiful deal.

Paul I'm glad you referenced Tom because I was going to pump that question that <unk> asked me I appreciate it.

Yes.

Yes, Thanks Paul.

The old BBB, a I think I got all the bees in there.

Yes, it was a great.

At that will help our industry for sure.

We're not really a currently attacks big taxpayer in the U S. So.

It will help in future years. It is not really something that we're going to benefit from this current year, but in future years it could be.

With all the specific impacts it could be $40 to $50 million.

<unk> for us going forward in the outer years.

Tom Yes that from 2000 2006 to 2030 that we can say that.

Yes, 40 to 50 million in that year.

Yes, that's probably a good number to think about it it depends on.

What what our tax position will be in the outer years, a lot of that's been driven by.

If we get a recovery in oil price, we might be we might be a bigger cash payer.

Depending on how it plays out, but yes, that's potentially that kind of frames it for us.

And second question follow up with.

With the.

Well productivity that you're seeing in Eagle Ford.

And you think that.

Do you have proof our lower Eagle Ford.

The opportunity set or what their potential.

Does that change how you look at the development plan for.

Paul Eagle Fone, I think up until now that it's always been okay, I'm going to keep Eagle Ford that 30% to 35000 barrels per day.

And then you're sort of at the back burn teal.

Yes.

Deep water production.

Production start to decline and at that point, we will use it to ramp up.

These new data changed that view at all thank you.

Great question, Paul I would say that it doesn't significantly change the way we want to use the asset in our total company portfolio I would expect to see us produce Eagle Ford and a 30% to 35000 net Boe per day range in the coming years, we will preferentially invest in our offshore business.

For two reasons, one the infrastructure that we access with offshore developments has a more defined life and if we don't act on those investments they may not be there in the future, whereas Eagle Ford Wells will be there in the future and also we tend to have really strong returns from our offshore investment opportunities. So we do we do plan to preferentially invest.

Offshore having said that I think that the results that we're seeing from these recent infill lower Eagle Ford Wells gives us confidence that the plan. We have developed for the mid term to long term, it's something we should have even more confidence in the results.

And that for Mon the Tupper, Montney I think <unk> seen that the five well pad.

Bring on the Appalachian want the 10 wells that bring on Daphne's is $19 2 million cubic feet per day for the 30 day IP.

How do you think that that is more of an exception or that you're seeing with the new decide that this is the average that you can.

So corresponding need that the future.

To maintain.

Painful you'd need to spend even less on Monday.

I think we had really nice well performance I think the completion design that we deployed which.

And enhanced proppant loading was very effective we've modified our flowback strategy to allow the wells to be as productive as they can be we were pretty thrilled with 10 wells, averaging $19 2 million cubic feet per day.

I see and that, uh, for uh, money the the, uh, top of money. I think you're saying that the 5. Well, that it, uh, bring on the average or the 10 world that bring on. The average is 19.2 million. Cubic feet per day for the 30-day IP.

Some of those wells were actually constrained by plant capacity, we actually ran out of capacity and over overhead.

Uh, do you think that that is more of an exception or that you think with the new design that this is the average that you can expect. So correspondingly that the future, uh, need to maintain the the panful. Uh you need to spend even less of money.

<unk> allowed us to be over deliverability compared to plant capacity.

Your question about how durable are those type of results I feel quite confident that in the next five to seven years. The wells that we will plan to drill to keep our Tupper West plant full have very similar geology to what we just developed and the completion style, we deployed should lead to similar results.

Great. Thank you.

Thank you.

Your next question comes from Carlos <unk> with Wolfe Research. Please go ahead.

Yes. Good morning team. Thank you for taking my question.

I would like to actually follow on that same line of thinking on Canada, considering how quarterly Ecu has been trading in their world.

Plan to drill to keep our Tupper West plant full have very similar geology to what we just developed and the completion style, we deployed should lead to similar results.

Or a commodity environment for that matter.

Great. Thank you.

Thank you.

Related to April pricing, where it would make sense to dial down your Montney annual program and exchange of perhaps more or leverage.

Next question comes from.

Carlos Escalante with Wolfie research. Please go ahead.

That's a very good question Carlos and it's something that we think about.

The capital efficiency of our Montney business is quite high we're able to bring on wells that at our type curve have breakeven of gas prices that are significantly below market.

Yeah, good morning, team. Thank you for taking my question. I would actually like to follow on that same line of thinking on Canada.

We also have a situation where we built we develop the plants that we currently flow through and then we sold them and are paying a throughput fee. So it makes sense for us at even extremely low gas prices to utilize the plants that we pay for anyway.

Considering how poorly acho has been trading is, is there a world, uh, or a commodity environment, uh, for that matter related to Aiko pricing? Where it would make sense to dial down your, your money annual program in exchange of perhaps more oil, Leverage.

<unk> to bring on wells that at our type curve have breakeven of gas prices that are significantly below echo market.

So between the capital efficiency of the new development and the low operating cost structure.

We also have a situation where we built we developed the plants that we currently flow through and then we sold them and are paying a throughput fee. So it makes sense for us at even extremely low gas prices to utilize the plants that we pay for anyway.

Our advantage to continue to invest in the asset even at extremely low eco prices, even below what you had been seeing on the screen lately on top of that we deploy a fixed price for selling and a diversification strategy, which has allowed us to realized gas prices that are in excess of echo quite materially.

So between the capital efficiency of the new development and the low operating cost structure. We are advantage to continue to invest in the asset even at extremely low eco prices, even below what you've been seeing on the screen lately on top of that we deploy a fixed price toward selling and a.

I think we were something like 44 per.

Per mcf above echo in the second quarter, we'd like to continue to do that type of thing we have long term diversification strategy in place to help support the asset I think that will help us continue to have more profitability.

The other thing I might point out just related to the asset because I think it's important.

<unk> strategy, which has allowed us to realized gas prices that are in excess of echo quite materially I think we were something like 44 cents per mcf above echo in the second quarter, we'd like to continue to do that type of thing we have long term diversification strategy in place to help support the asset and I think that will help.

Is the LNG, Canada facility that is ramping up on the west coast of Canada.

<unk> is currently having throughput at a relatively low level and should ramp up from I guess, two or 300 million cubic feet a day to two Bcf a day in the coming year, we think that'll help echo quite a bit and I'll point out that we are physically connected to that plant and in fact in the month of July delivered gas through.

Continue to have more profitability.

The other thing I might point out just related to the asset because I think it's important is the LNG, Canada facility that is ramping up on the west coast of Canada.

The pipeline from our plants to LNG, Canada as part of a commissioning our testing process for that new pipeline segment that allows us to flow. There. So we're watching the whole western Canadian natural gas market and think there may be an opportunity for us to either continue to be supporting the asset.

Is it currently having throughput at a relatively low level and should ramp up from I guess, two years or 300 million cubic feet a day to two Bcf a day in the coming year, we think that'll help echo quite a bit and I'll point out that we are physically connected to that plant and in fact in the month of July delivered gas through.

With plant level capacity or or even in the future possible expansions out past 2030, if if the LNG global demand kind of matches.

Our expectations.

Thank you that makes sense.

And then back to exploration. So I mean, you've always been asked a lot about the specific cause the war, but the eni.

With plant level capacity or or even in the future possible expansions out past 2030, if the if the LNG global demand kind of matches.

Discovery, which is adjacent to where you intend to drill your appraisal and exploration wells.

Our expectations.

<unk> has had some success so I wonder.

Thank you that makes sense.

On the first part of my question is there any read through that there's maybe a similar depositional environment to what Youre looking for.

And then back to exploration. So I mean, you've probably been asked a lot about the specifically around call. It the war, but the.

And then second part.

Ni.

If you could perhaps frame and benchmark this opportunity relative to what you see in Vietnam apology there'll be obviously a step ahead.

Discovery, which is adjacent to where you intend to drill your appraisal and exploration wells.

That'd be helpful.

<unk> has had some success so I wonder.

Sure Great question actually.

On the first part of my question is there any read through that there's maybe a similar depositional environment to what Youre looking for.

Prospect that we will drill first on blocks Ci 502 is testing the same play type as Eni's Marine Onex, well cloud discovery the same exact play type.

And then second part.

If you could perhaps frame and benchmark this opportunity relative to what you see in Vietnam, and knowledge and that would be non so obviously a step ahead.

Is a slightly shallower interval.

And we also have a potential in the future to test the potential up dip extension of the cloud discovery onto our block 500, too. So it should be very similar geologically has similar type of fluid type.

That'd be helpful.

Sure Great question actually.

Prospect that we will drill first on blocks Ci 502 is testing the same play type as Eni's Marine Onex, well cloud discovery the same exact play type.

And potentially a little oil year, we think but the same type of risk profile that they would've had we're quite excited about it and contrasting the opportunity set we have here and code of law with Vietnam has two significant differences I think that the.

Is a slightly shallower interval.

Fiscal terms that we Havent code of law in terms of the PSC contract and also our ownership structure at 90% working interest allows for with success.

Potentially a little oil here, we think but at the same type of risk profile that they would've had we're quite excited about it contrasting the opportunity set we have here in Cote d'ivoire with Vietnam has two significant differences I think that the.

<unk> exploration success to be a much more significant outcome for us as a company. We're excited about our Vietnam. We think will continue to find more oil in Vietnam. It will be a major contributor to us as we've highlighted earlier potentially having a $30 to 50000 barrel a day business for US there the code of wall with success of one or more of these prospects would be a.

Fiscal terms that we Havent code of law in terms of the PSC contract and also our ownership structure at 90% working interest allows for with success.

<unk> added to our resources and the fiscal terms are very strong so financially they would be even more significant than the Vietnam business.

<unk> exploration success to be a much more significant outcome for us as a company. We're excited about our Vietnam. We think will continue to find more oil in Vietnam. It will be a major contributor to us as we've highlighted earlier potentially having a $30 to 50000 barrel a day business for US There Dakota wall with success of one or more of these prospects would be a.

Very helpful color. Thank you.

Thank you.

Thank you. Your next question comes from Charles Meade with Johnson Rice. Please go ahead.

Okay.

Yes, good morning, Erik do you and your team there.

Ill pick up right, where you left off and.

Adder to our resources and the fiscal terms are very strong so financially they would be even more significant than Vietnam business.

As I look at those <unk> prospects.

Obviously, the upside cases is up.

Very helpful color. Thank you.

As impressive but also drilling those at 90% can you can you give us an idea about.

Thank you.

Thank you. Your next question comes from Charles Meade with Johnson Rice. Please go ahead.

I know this may be getting getting ahead, you've got to drill your first well, but I wanted to get an idea of what would the success case look like would you stay at 90% and the development scenario how many.

Yes, good morning, Erik do you and your team there.

Wanted to pick up right, where you left off and.

As I look at those those prospects.

We see the upside cases is up.

Yes.

How many appraisal wells would you need to drill in.

As a precedent, but also drilling those at 90% can you can you give us an idea about.

What would what would the success case on one of these big prospects look like.

Great question, Charles obviously, we would be thrilled to make a discovery of the scale that we think we have to test here in the <unk> upward range.

Success case, there these are deepwater developments and those obviously have a range of outcomes in terms of the development costs. It will put significant pressure on us in terms of development Capex near term appraisal capital spending will be fairly modest something that we would definitely be able to handle within our current ownership structure.

Yeah.

How many appraisal wells would you need to drill and what would what would the success case on one of these big prospects look like.

Great question, Charles obviously, we would be thrilled to make a discovery of the scale that we're at.

We were to make one large discovery here would be something we would easily be able to fund within.

Think we have to test here in the Mena upward range.

Success case, there these are deepwater developments and those obviously have a range of outcomes in terms of the development costs. It will put significant pressure on us in terms of development Capex near term appraisal capital spending would be fairly modest something that we would definitely be able to handle within our current ownership structure. If we were.

The kind of range of annual Capex that we've been talking about we may make adjustments to the rest of our capital program to make room for a little bit of additional spending here, but it wasn't overly stressed us more than one would be a significant draw on additional capital to develop so again near term appraisal capex would not be.

To make one large discovery here would be something we would easily be able to fund within.

Something that's beyond what we kind of expect to do with our overall global exploration and appraisal program development capex potentially be material. If you think about it.

A range of deepwater development cost structure as you are probably 10 to $15 a barrel development cost and obviously, if you find a billion barrels that leads to a lot of capex. So we would consider with tremendous success one of the things we would evaluate it would be a farm down of some of our ownership to help fund development, but it's not something that we are.

Something that's beyond what we kind of expect to do with our overall global exploration and appraisal program.

Pre determining we would do it would just depend on.

Capex could potentially be material, if you think about.

What kind of scale of results and the timing we wanted to move those forward.

A range of deepwater development cost structures, you're probably 10 to $15 a barrel development cost and obviously, if you find a billion barrels that leads to a lot of capex. So we would consider with tremendous success one of the things we would evaluate it would be a farm down of some of our ownership to help fund development, but it's not something that we are.

A couple of points I'll make we are the operator of the blocks, which allows us significant flexibility in the pace of both appraisal and development. If you contrast that with some other companies of our scale that were non operated in large developments that had less control over our Capex program.

It gives us some some advantages in terms of being able to execute what we want.

Pre determining we would do it would just depend on.

What kind of scale of results and the timing we wanted to move those forward.

Your other question about how many appraisal wells will be needed. It really it's not an answer you probably want to hear but it really depends on what we find we don't know exactly how many wells will be needed, but I would say its likely if you. If you discovered a field that had the potential to be of the size each of the discoveries would probably require at least two more appraisal wells in.

It gives us some some advantages in terms of being able to execute what we want.

That's only just ballpark it that's not based on any overwhelmingly modeled science is just that's the kind of thing that makes sense based on historical type of performance.

Your other question about how many appraisal wells will be needed. It it really it's not an answer you probably want to hear but it really depends on what we find we don't know exactly how many wells will be needed, but I would say its likely if you. If you discovered a field that had the potential to be of the size each of the discoveries would probably require at least two more appraisal wells in.

We see exploration well costs here in the $40 million to $60 million, a piece, depending on well depth and water depth, so theyre not too expensive and they allow us to test significantly large resource.

That's only just ballpark it that's not based on any overwhelmingly modeled science. Its just thats the kind of thing that makes sense based on historical type of performance.

Yes.

It's really great Eric that's exactly the kind of answer I was looking for.

I was trying to tie it back to you have to appraise in Vietnam and anything you five years youre going to have to price, but that's a helpful. Elaboration on your thinking and that's it for me.

We see exploration well costs here in the $40 million to $60 million, a piece, depending on well depth and water depths, so theyre not too expensive and they allow us to test significantly large resource.

So much vishal.

Thank you, ladies and gentlemen, as a reminder, if you have any questions. Please press star one.

Your next question comes from Leo Mariani with Roth Capital. Please go ahead.

Yeah.

Really great Eric that's exactly the kind of answer I was looking for.

Yes, Hi, I was hoping you guys could talk a little about offshore Canada.

Trying to tie it back to you have to appraise in Vietnam and anything you find here youre going to have to price, but that's a helpful. Elaboration on your thinking and that's it for me. Thanks.

I know you guys had an issue here with a barge I think in the first quarter, but looking at your volumes, let's take that kind of continued to run.

Thanks, so much thanks Charles.

Thank you, ladies and gentlemen, as a reminder, if you have any questions. Please press star one.

Hello here.

Just kind of wanted to get a sense of what's happening. There I think you guys were hoping to get some maybe higher on time and utilization on China.

Your next question comes from Leo Mariani with Roth Capital. Please go ahead.

Yes, Hi, I was hoping you guys could talk a little about offshore Canada.

Just looking at your guidance something against not having in the near term.

Okay.

I know you guys had an issue here with a barge I think in the first quarter, but looking at your volumes. It looks like they've kind of continued to run kind of low here of late.

Yes, thanks for that I'll give a high level comment I may pitch it to Chris to give you additional context. The first one is the the first quarter issue around the shuttle tanker was resolved in the first quarter, that's not an ongoing issue not something to be concerned about.

Just kind of wanted to get a sense of what's happening. There I think you guys were hoping to get some maybe higher run time and utilization on churn over but just looking at your guide is something thats not happening in the near term.

In general we have been somewhat disappointed with the run time of the Terra Nova facility, but we had lower than expected uptime at both Hibernia and turnover in the second quarter as you look toward the second half of this year we have.

Okay.

Less optimism around uptime and turnover than we've had in the past and thats affecting our third quarter guide for Canadian production, which unfortunately is 100% oil and therefore impactful to our third quarter oil volumes Kristina. If you have any additional color I just just to add to that we've been they did have some planned downtime that did go over a little bit. So that's part of the reason.

In general we have been somewhat disappointed with the run time of the Terra Nova facility, but we had lower than expected uptime at both Hibernia Terra Nova in the second quarter have you look toward the second half of this year we have.

As well.

So it's been a little bumpy and like it's been in the past but.

Less optimism around uptime and turnover than we've had in the past and thats affecting our third quarter guide for Canadian production, which unfortunately is 100% oil and therefore impactful to our third quarter oil volumes, Chris I don't if you have any additional color that just just to add to that we've been with they did have some planned downtime that did go over a little bit. So that's part of the reason.

The wells have been strong when they are producing so it's just a matter of kind of getting the mechanical side of the facility.

Smoothed out.

When they are performing very well and when they're down they're zero or near zero. So it's disappointing.

Alright, Okay Thats helpful.

Wanted to touch base on LOE.

As well.

Obviously, you guys are planning to get the bulk of the near term Workovers behind you here guiding to kind of this 10 to $12 per barrel LOE leaves again into the second half.

It's been a little bumpy and like it's been in the past but.

The wells have been strong when they are producing so it's just a matter of kind of getting the mechanical side of the facility kind of smoothed out.

Wanted to kind of just touch based on how you're kind of seeing that sustainability of that LOE had been kind of a decent amount above that level I guess it came in in that range in the second quarter, but.

When theyre up performing very well and when they're down they're zero or near zero. So it's disappointing.

Alright, Okay Thats helpful.

As such based on low.

Obviously, you guys are planning to get the bulk of the near term Workovers behind you here guiding to kind of this 10 to $12 per barrel LOE as we get into the second half just wanted to kind of just touch base on how you're kind of seeing that sustainability of that LOE has been kind of a decent.

Tenants will all of the right run rate going forward or do you think theres going to be periods, where maybe it's going to go sort of above that and maybe some of the workovers creep back in at some point.

Okay.

Leo I think 10 to $12 per barrel range for a company is a pretty good number for us. If you look at our second quarter of this year. If you normalize out the offshore workovers, our LOE would have been $9 seven a Boe.

Amount above that level I guess it came in in that range in the second quarter, but you think tenants will all of the right run rate going forward or do you think theres going to be.

So if you get to a very low workover trend, which is what we expect.

<unk>, where maybe it's going to go sort of above that and maybe some of the workovers creep back in at some point.

Typical year.

You would have a little bit of room for some workover activity you can still be intend to $12 per barrel range, obviously, our production profile isn't perfectly flat from quarter to quarter.

Okay.

Leo I think 10 to $12 per barrel range for a company is a pretty good number for us. If you look at our second quarter of this year. If you normalize out the offshore Workovers are low we would have been $9 seven per Boe.

Possible that in the first quarter of next year, you could see low trend just a little bit higher than that but I still feel like notionally of 10 to $12. A barrel range is a pretty good number for us on a go forward basis.

So if you get to a very low workover trend, which is what we expect on a typical year.

I would just like to add that.

You would have a little bit of room for some workover activity you could still be intend to $12 per barrel range. Obviously, our production profile isn't perfectly flat from quarter to quarter, it's possible that in the first quarter of next year, you could see low trend just a little bit higher than that but I still feel like notionally of 10 to $12 barrel range is a pretty good.

Look at Eagle Ford, specifically, because that's where we got a lot of changes we went from $13 a Boe down to just over eight so we had very little fixed cost for these karnes wells and just adding that volume makes a significant difference from quarter to quarter.

Got it okay. So it sounds like you feel like there is a structural change there in Eagle Ford.

For us on a go forward basis, and I would just like to add that if you look at Eagle Ford specifically, because that's where we got a lot of changes we went from $13 a Boe down to just over eight so we had very little fixed cost for these karnes wells and just adding that volume makes a significant difference from quarter to quarter.

Yes, absolutely the Eagle Ford team did a tremendous job of cutting costs and which I featured in my stockholder letter I think it's a really exceptional outcome for us and a durable.

Outcome in terms of the reduced cost structure for Eagle Ford, which is quite helpful.

Okay. Thank you.

Thanks Bill.

Thank you.

Got it okay. So it sounds like you feel like there is a structural change there in Eagle Ford.

Next question comes from Jeff J, We Daniel LNG Partners. Please go ahead.

Yes, absolutely the Eagle Ford team did a tremendous job of cutting costs and which I featured in my stockholder letter I think it's a really exceptional outcome for us and a durable outcome.

Hey, guys I was just sort of wondering if you could maybe give us a little more color on what changed in your completions in karnes.

And or and also if there is.

Outcome in terms of the reduced cost structure for Eagle Ford, which is quite helpful.

The completion change by itself sort of explains this outperformance or if there are other factors that may have contributed.

Okay. Thank you.

Thanks Neil.

Thank you. Your next question comes from Jeff J, We Daniel LNG Partners. Please go ahead.

Great.

What we do in our completion design, we just quite a few things our stage spacing, our perforation design, how we pump the job how we ramp up the sand proppant loading how we do fluid loading we make adjustments to all of those things as we kind of fine tune our completion design for.

Hey, guys I was just sort of wondering if you could maybe give us a little more color on what changed in your completions in karnes.

Or and also if there is.

The completion change by itself sort of explains this outperformance or if there are other factors that may have contributed.

Each area of our operations in.

In the case of the Turner pad, which I mentioned was an infill pad, we actually dialed down the fluid loading and proppant loading compared to our typical design, which seem to lead to a better outcome and that will be something that we'll continue to fine tune going forward.

Great.

What we do in our completion design, we just quite a few things.

Stage spacing, our perforation design, how we pump the job how we ramp up the sand proppant loading how we do fluid loading we make adjustments to all of those things as we kind of fine tune our completion design for each area of our operations.

In parallel with how we pump the completion, we're also optimizing our flowback strategy and using some tools to help guide in the early life choke bump progression of those wells to maximize both near term rate and ultimate recovery.

Excellent.

Thanks, Jeff.

Thank you there are no further questions from our full lines I would now like to John the call back over to you Eric Hambly for any closing remarks.

In parallel with how we pump the completion, we're also optimizing our flowback strategy and using some tools to help guide in the early life choke bumps progression of those wells to maximize both near term rate and ultimate recovery.

Thank you for your interest in Murphy Oil Corporation I'd like to close by again, recognizing our employees for their commitment to providing energy that empowers people. So thank you and that concludes our call have a great day.

Excellent.

Thanks, Jeff.

Thank you there are no further questions from our full lines I would now like to Jim the call back over to you Eric Hambly for any closing remarks.

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

Okay.

Yeah.

[music].

Yes.

Q2 2025 Murphy Oil Corp Earnings Call

Request a DemoDemo

MUR

Murphy Oil

Earnings