Murphy Oil Corporation (NYSE:MUR) Q2 2024 Earnings Call Transcript

Murphy Oil Corporation (NYSE:MUR) Q2 2024 Earnings Call Transcript August 8, 2024

Murphy Oil Corporation beats earnings expectations. Reported EPS is $0.834, expectations were $0.73.

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

Kelly Whitley: Thank you, Operator. Good morning, everyone, and thank you for joining us on our second quarter earnings call today. Joining us is Roger Jenkins, Chief Executive Officer; along with Eric Hambly, President and Chief Operating Officer; and Tom Mireles, 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, financial amounts are adjusted to exclude non-controlling interests in the Gulf of Mexico. Slide 2. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.

As such, no assurances can be given that these events will occur or that projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy’s 2023 Annual Report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger Jenkins. Roger?

Roger Jenkins: Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. On Slide 3, I would like reiterate our corporate priorities of delever, execute, explore and return. As we continue to progress our capital allocation framework in the second quarter, we repurchased $50 million of senior notes through open market repurchases. Murphy also remains fully committed to achieving our long-term debt goal of $1 billion. We produced 181,000 barrels equivalent per day in the second quarter, with 50% oil volumes, as we exceeded guidance onshore while delivering our offshore well program. We also advanced our Lac Da Vang field development project in Vietnam by awarding key facilities and pipeline contracts during the quarter.

Also during the second quarter, we drilled a discovery well at the non-operated Ocotillo well in the Gulf of Mexico, and we are very pleased at the results. Return to Vietnam are preparing to spread the first of two operated exploration wells in the third quarter. Looking to our fourth priority of return, our share repurchase program continued in the second quarter with 56 million shares repurchased plus an additional 44 million of shares repurchased in the third quarter through August 7. Year-to-date, we’ve repurchased $150 million of our stock or 3.8 million shares at an average price of $39.70 per share. As we remain focused on progressing our shareholder returns, I’m excited to announce today that our Board has approved a revision to our capital allocation framework that allows us to move to Murphy 3.0 now with a current debt level of $1.3 billion.

Moving to Slide 4. Murphy will now allocate a minimum of 50% of adjusted free cash flow to shareholders focused on buybacks. The remaining adjusted free cash flow will be allocated to our balance sheet as we remain committed to our long-term $1 billion long-term debt goal target. Our Board is also elected to increase our share repurchase authorization by $500 million. As of August 7th, we have approximately $800 million remaining. I’d also like to highlight today that most impressively, we have fortified our balance sheet significantly in the past few years since launching the capital allocation framework 2 years ago today, we’ve repurchased $300 million of shares and increased our dividend by 70%. When you look back further to year-end 2020, we’ve utilized more than $2 billion of adjusted free cash flow to repurchase shares and reduce debt by $1.75 billion, achieving nearly $90 million in annual interest expense savings and giving us one of the top, if not the top, balance sheet in all of E&P.

On Slide 5, in the second quarter, Murphy produced an average of 181,000 barrels equivalent per day with 91,000 barrels of oil. We again realized a slight premium to WTI with a realized price of more than $81 per barrel, while our realized NGL pricing was nearly $22 per barrel, and our net gas was $1.45 per 1,000 cubic feet. Overall, we generated $746 million of revenue in the quarter, excluding NCI. I’ll now turn the call over to our CFO, Tom Mireles, for an update on our financial results. Tom?

Tom Mireles: Thank you, Roger, and good morning, everyone. Slide 6. Murphy reported $128 million of net income in the second quarter, or $0.83 per diluted share, and $124 million of adjusted net income, or $0.81 per diluted share. We generated $396 million of adjusted EBITDA in the quarter with $292 million of accrued CapEx excluding non-controlling interest. As Roger just mentioned, we have continued executing our capital allocation framework while supporting a strong dividend in a front-loaded CapEx plan. Since August, 2022, when we first announced the framework, we have repurchased more than 7 million shares, or 300 million of stock, at an average price of $41.72 per share. We now have 150 million shares outstanding. I look forward to seeing what we will accomplish with the enhanced shareholder framework returns as part of Murphy 3.0. Slide 7.

Murphy maintains strong liquidity with $1.1 billion available as of June 30. During the second quarter, we repurchased a total of $50 million of long-term debt through open market transactions comprised of $26.5 million of our 2027 senior notes and $23.5 million of our 2028 senior notes. As of June 30, we had $1.28 billion of long-term debt outstanding with our next maturity over 3 years away in December 2027. Slide 8. Our 6th annual sustainability report was released this week and includes disclosures regarding Murphy’s ongoing environmental stewardship, strong governance oversight and positive impacts on our people and communities. We have been recognized for our efforts with awards from a variety of organizations, including being named as a Best Place for Working Parents by the Greater Houston Partnership for a third year in a row.

Additionally, we were named one of America’s Most Responsible Companies in 2024 by Newsweek. With that, I’ll turn it over to Eric Hambly, our President and Chief Operating Officer, to discuss our operational updates.

Eric Hambly: Good morning. Slide 10. Murphy produced 28,000 barrels of oil equivalent per day in the second quarter from the Eagle Ford Shale with 86% liquids and due to stronger well performance, we exceeded guidance by 1,700 barrels of oil equivalent per day. We brought online 11 operated wells in Catarina and four gross non-operated wells in Tilden during the quarter. We were on track to bring on five operated and three gross non-operated wells in Tilden in the third quarter. Our 2024 Catarina wells are showing great performance compared to Murphy’s recent historical average, and I’m also pleased at the results we have seen across our completions activities this year. Our completed lateral foot per day has increased by approximately 50%, while our completion cost per completed lateral foot is down nearly 40%.

Additionally, we’ve reduced our drilling diesel cost by 10% after installing EcoCell on our Patterson-UTI rig. Slide 11. We produced an average of 400 million cubic feet per day in the second quarter in Tupper-Montney, exceeding guidance by nearly 20 million cubic feet per day, primarily due to well performance as we brought online 13 wells and completed our 2024 program. Also during the quarter, we achieved a record high peak gross production rate of 496 million cubic feet per day, thereby reaching processing plant capacity in conjunction with the sanctioning of our Tupper Montney plant expansion in the fourth quarter of 2020. We continue seeing great well performance from our optimized completion design. In particular, our average IP30 rate in our Tupper main area has increased approximately 120% since 2019, and more than 200% since 2016.

Overall, 5 of our 2024 wells are among Murphy’s top 20 Tupper Montney wells based on IP30 rates. Slide 12. In the second quarter, our Kaybob Duvernay asset produced 4,000 barrels of oil equivalent per day with 72% liquids, which was slightly above guidance. Murphy brought online three operated wells during the quarter, which completes our well delivery program for 2024. We’re also seeing some of our highest rates in company history for Kaybob Duvernay with an average peak rate of 1,900 barrels of oil per day. This ranks in the top tier among our peers when normalized for lateral length. Overall, recent well performance has mirrored our Catarina wells in the Eagle Ford Shale, and I look forward to seeing further results. Slide 13. Murphy produced an average 74,000 barrels of oil equivalent per day in the second quarter from the Gulf of Mexico with 82% oil volumes.

We progressed our Gulf of Mexico well program in the second quarter as we brought online the operated Khaleesi #4 well and non-operated Lucius #11. We also drilled the operated Mormont #3 well which is on track to come online in the third quarter. In offshore Canada, we’ve produced an average of 8,000 barrels of oil equivalent per day with 100% oil. Non-operated Terra Nova production was impacted by additional downtime during the quarter. Slide 14. I’m pleased that we are nearing completion of our 2024 workover and project program in the Gulf of Mexico as we advance operations in the second quarter. Early in the third quarter, we brought online the operated Neidermeyer #1 sidetrack well, while our operating partner completed the Kodiak #3 well workover.

The operated Dalmatian #2 Subsea safety valve repair is progressing, and we forecast it will come online later in the third quarter. Our workover expenses, which are included in our lease operating expenses, totaled $68 million for the second quarter, which included the cost of the Neidermeyer sidetrack well. We forecast $35 million of workover expenses for the third quarter of 2024. Slide 15. In Vietnam, we have been progressing our plans for our Lac Da Vang field development project. In the second quarter, we awarded facilities and pipeline contracts, and we expect to award the remaining major contracts by the year-end 2024. We look forward to begin drilling our development wells in 2025 and remain on schedule for achieving first oil in late 2026.

Slide 17. We recently completed our Gulf of Mexico exploration program for the year, and I’m excited to announce a discovery at the non-operated Ocotillo #1 well, where our operating partner found approximately 100 feet of net pay across two zones. The partner group is currently evaluating results to determine the next steps and we look forward to advancing this project. Also during the quarter, we completed drilling the non-operated Orange #1 exploration well and encountered non-commercial hydrocarbons. Our operating partner plugged and abandoned the well. Slide 18. We are preparing to begin our Vietnam exploration program and we plan to spud the Hai Su Hong exploration well in Block 15-217 late in the third quarter. The rig will then move to drill the Lac Da Hong exploration well in Block 15-105 in the fourth quarter.

We forecast approximately $30 million in total net drilling costs for the wells and look forward to seeing the results of these wells as they provide the potential to create a more sizable business in Vietnam. Slide 19. Our seismic reprocessing work continues to progress for our acreage in Cote d’Ivoire. We anticipate receiving final data by year-end 2024. From our current evaluation, we are pleased at the multiple opportunities available across the exploration types, in addition to recent nearby discoveries announced by other operators. Murphy will continue our evaluation as additional data becomes available and will likely begin preparations for an exploration program in 2025 or 2026. At the undeveloped Paon discovery, Murphy remains on track to submit a field development plan by year-end 2025.

Slide 21. For the third quarter of 2024, we forecast total production of 181.5 to 189.5 thousand barrels of oil equivalent per day with approximately 50% oil volumes. This range assumes 3,900 barrels of oil equivalent per day of potential Gulf of Mexico storm downtime as well as 2,900 barrels of oil equivalent per day of planned onshore downtime and 2,600 barrels of oil equivalent per day a planned Gulf of Mexico downtime. Murphy forecasts spending approximately $270 million of accrued CapEx in the third quarter. For full year 2024, we are maintaining our production guidance of 180,000 to 188,000 barrels of oil equivalent per day with 52% oil volumes. Currently, we expect to be at the lower end of this range due to operational impacts in the Gulf of Mexico.

In particular, the development plan for an operated well in the Samurai Field was altered to a single zone to maximize total field recovery. Additionally, extended operations at the planned Neidermeyer #1 sidetrack well delayed the rig from commencing the Dalmatian well workover. We also maintained our accrued CapEx range of $920 million to $1.02 billion, excluding NCI. And with that, I will turn it back to Roger.

Roger Jenkins: Thank you, Eric. Effective at year end, our strategy remains unchanged, with the one exception that we’ll be now executing Murphy 3.0 of our capital allocation framework and forecast reaching our $1 billion long-term debt goal in mid 25. Longer term, we plan to reinvest approximately 45% of our cash flows, enabling us to achieve average production of approximately 210,000, the 220,000 barrels equivalent per day, with always more than 50% oil weighting. Murphy will continue to generate ample free cash flow to allocate toward further share returns and accretive investments, as well as supporting any exploration success. Additionally, as part of this plan, we remain committed to achieving metrics that are consistent with the investment rating, and we’re pleased with the rating agency outlook improvements achieved this past spring.

Turning to 23, as we close our call today, we had another good quarter, which set us up for an exciting second half of the year. Most importantly, Murphy’s accelerating shareholder returns by revising our capital allocation framework and maintaining our $1 billion long-term debt goal. In support of this, our Board increased our share repurchase authorization. We’ll continue executing our plan and have been exceeding production guidance across all our onshore assets while advancing a solid Gulf of Mexico well program and work over projects. In exploration, we expanded our Gulf of Mexico portfolio with a discovery and preparing to launch an exciting Vietnam exploration program in the third quarter where we have a long-term development going as well.

In closing, I’d like to thank our employees for their ongoing efforts to support Murphy’s success. I look forward to what we will achieve as we close out the second half of ’24. With that, we will turn it back over to our to our operator and look forward to your questions this morning.

Q&A Session

Operator: [Operator Instructions] Your first question comes from Neal Dingmann, Truist Securities. Please go ahead.

Neal Dingmann: Good morning, Roger. Nice quarter. My first question is …

Roger Jenkins: Thanks, Neal.

Neal Dingmann: … on your decision that — my question is around the decision to accelerate. It was nice to see the decision to accelerate the 3.0 plan. Was this driven more by the current stock price or investor discussions or just one of the decisions behind this. And then when you decide now behind the stepped up shareholder — potential shareholder return, and you always see a lot of interesting — creative [ph] potential acquisitions. Is this just simply a return exercise? How do you decide between these two?

Roger Jenkins: Thank you so much, Neal. One thing about when our Board meets, we have a lot of ownership on our Board, probably second of all of the MPs. So it’s a little bit of a different matter when we meet about returns. This was the — my idea to do this, it wasn’t from investor outreach. I believe our framework were successful. We just started benchmarking with Tom and his team with a leading balance sheet we have. We also see a lot of openness to credit markets today. And you’re the leading balance sheet. You have a bit of a price dislocation this year in our equity pricing, and we still maintaining that $1 billion goal. And that hasn’t been changed. It’s just pushed out a couple of quarters, if you will, or three. And we decided to go ahead and move today and start allocating more returns.

And one thing very key, Neal, about this, and I want to — can’t emphasize it enough, from the original framework disclosure 2 years ago probably within a day or two of now, it says minimum of 50%. So we’ll go over if we continue to see price dislocation. It’s minimum and it’s always been minimum. As to your question on M&A, that would be adjusted out of our formula, but we would pull back on the cash flow we have and debt of that could be associated with that as well. We continue to review M&A. We’re excited about M&A opportunities. We have a lot of competition in non-operated business in the Gulf of Mexico. We usually strive where you need to operate and improve or execute better, which is what we do. And M&A is still forefront, that hasn’t been changed.

We’re still having the same discussions and meetings on that. Just felt like had a great balance sheet, a leading balance sheet through benchmarking of any type of metric and moved it forward and glad we did and excited about doing that the rest of the year. Also, I think with M&A and the possibilities, people will say, well, you may not ever reach a billion, you may do this, you may do that. But now we close that off and moved it.

Neal Dingmann: Well said. And then just second question on the guide, oil guide for remainder of the year. Was the change just due to, I guess, activity in the Gulf or maybe if you can just talk about just oil production for remainder of the year, how that’s impacted both offshore and onshore? Thank you.

Roger Jenkins: Well, Eric is going to handle the offshore and onshore questions today. Go ahead, Eric.

Eric Hambly: Okay, thanks very much. Neal, the impacts that we highlighted earlier in our call are driving us to be toward the lower end of our original annual production guidance range. Main issues there are a well in Samurai field had been producing from two zones and we elected to produce them one at a time going forward. We did that based on what we learned from the wells we produced it, and in order to maximize the ultimate recovery. It does have a negative instantaneous oil rate for us in the Samurai field of about 4,000 barrels equivalent per day, which is driving a significant change in the last half of the year type of production rate. The other impact was that the Neidermeyer #1 well that we did a sidetrack on took a little bit longer to complete that operation.

It came online slightly later than our earlier guidance and because the rig that was on that well is moved to the Dalmatian DC4 #2 Subsea safety valve repair job, it delayed the online timing of that well. So — it does affect us a little bit. If you give me a minute here, I’ll explain what will happen as we head toward later in the year. So in our offshore business, we’ll see production growth in the fourth quarter versus the third quarter due to a number of factors. That total increase is probably in the range of 8,000 to 9,000 barrels a day. It’s driven by the DC4 #1 being online, coming online, it’s currently offline. The Kodiak well being online for a full quarter instead of most of a quarter. The Mormont 3 well will come online, and then in the fourth quarter we’ll have a little bit less storm downtime.

So we’ll see some nice growth in our offshore business, about 8,000 to 9,000 barrels a day in the fourth quarter, and that’ll be offset by — partially offset by decline in our onshore business, which is typical since we have a very limited number of wells to come online in the rest of the year in our onshore business.

Neal Dingmann: Perfect. Thank you all.

Roger Jenkins: Also, Neal, keep in mind right there in the guidance, we have hurricane season. We’re an offshore operator and that’s a big number for the third quarter and we have to make sure we account for that as well. There’s no hurricanes, it’d be way higher.

Neal Dingmann: That’s right. Great point. Thank you, Roger.

Roger Jenkins: Thank you, Neal. Take care.

Operator: The next question comes from Arun Jayaram from J.P. Morgan. Please go ahead.

Arun Jayaram: Hey, good morning, gentlemen.

Roger Jenkins: Good morning, Arun.

Arun Jayaram: Good morning, Roger. I was wondering if you could just give us an update on the exploration program in Vietnam. It sounds like you’ll be spudding the first well by the end of the — before the end of the third quarter, but maybe just give an update on that program.

Roger Jenkins: I’ll add high-level, and Eric dig in a bit to the details. We have a big project going there, a 100 million barrel field that we’re developing. We’ve been in Vietnam for a while. We were brought to Vietnam by their government because we were very successful in a shallow water business in Malaysia, which both Eric and Tom ran, part of their career. I was more of a deep water guy in the old days. And so we have that going for us, and we have lots of prospects in Vietnam, many who chose to drill a couple of big ones in a row here that are very exciting in a lower risk basin to help build up possibly a big business for us in Vietnam. And that’s kind of the high-level picture. And Eric will walk you through the couple of wells we’re about to go here.

Eric Hambly: Thanks, Roger. I just wanted to highlight that we’re very excited about our exploration wells in Vietnam. The rig that we’re going to use to drill those is currently working with another operator in Vietnam, and when they’re done, the rig will come to us. We expect to spud our well late in the third quarter. The first well that we’ll start drilling will be on block 15-2/17, the Hai Su Vang prospect, where we’re targeting a mean to upward volume of 170 million to 430 million barrels. It’s a very nice looking prospect, sizable prospect, that’ll test the same type of geology as our Lac Da Vang development project. So looking forward to that. After we complete that exploration well, we’ll move to the block 15-105, where we’ll drill the Lac Da Hong prospect, and that’s targeting a 65 million to 135 million barrel stratigraphic play, another very exciting well for us.

Overall, these wells in Vietnam have the potential to really prove up a really material, sizable, exciting business for us in Vietnam with some success. So looking forward to them. As you know, our exploration is a core tenant of our focus area and these are looking to be great prospects for us to drill.

Arun Jayaram: Great. My follow-up is just on Slide 2022 — Slide 22, pardon me. You highlight the 3-year program which will deliver 5% growth CAGR to 195 MBOE per day at 95,000 barrels, BOEs of offshore. Can you help us think about some of the growth drivers, Roger, in 2025? Obviously, in 2026 you’ll start getting some volumes in Vietnam, but just help us think about some of the growth drivers next year.

Roger Jenkins: Well, we’re putting on a lot of nice wells at both our Samurai field, which has been a very successful field with millions of barrels of reserves still there today, over 60 million barrels remaining in Samurai today. We’re drilling a nice well at the Khaleesi-Mormont field. We put one on, we have two more to go. They have a full year of those rates. These are very high rate wells. Eric just ran through a litany of work over things that we’ve had this year that’ll be flowing for the full year. We’re hopeful that Terra Nova can improve their operations a bit and get back to a nice level, which they have achieved at several times. And that’s the gist of what we’re trying to do there. But this is a 3-year average deal, not necessarily 25. But we have many opportunities of beyond and many opportunities that will flow for the whole year as you put on these wells, and they come in with pretty high rates. So that’s how that’s going to march upward on that, Arun.

Arun Jayaram: Thank you, sir.

Roger Jenkins: Thank you.

Operator: Your next question comes from Neil Mehta from Goldman Sachs. Please go ahead.

Roger Jenkins: Good morning, Neil.

Neil Mehta: Good morning. Good morning, sir. Thanks for taking the time. I had a couple of Canada questions for you, if you will. I guess the first is, we’re in a challenging environment for ACO. I think there’s an interesting multi-year outlook for Western Canadian gas prices from where we are here. But just your perspective on the way some of the U.S. gas producers are holding back molecules until we get into a better environment. It makes sense to change the cadence of your production profile to monetize into a better price environment.

Roger Jenkins: Thank you for that Neil question, great question. We’re a little different than big gas only players in the U.S. We have a plant and an infrastructure can only handle 500 million a day, so it’s not an enormous multi-BCF business. We have, as benchmarked by your competitors and many other times in the industry, the lowest breakeven in North America adjusted for ACO and for C-dollar type of exchange. So we have very extremely low breakeven prices. We have hellacious wells. We have commitments to our pipelines into this plant. And so far economically, it’s shown us to want to do that. And we see a future there with LNG Canada over a long haul. We have relationships that are key to us in differentiating to our peers.

Both Eric, Tom, and I all lived in KL. We’re very well known in Asia, very well known to deliver gas into LNG systems. We’re a little different animal there. There are multiple LNG outlets being built in Western Canada. But right now, it’s better for us with the commitments we have at our plant and pipes to continue on with our low breakeven and continue to make free cash flow there with the assets that we have. But I understand that question and that’s how we’re going at this time.

Eric Hambly: Also, Neil, one more thing, pretty good hedging situations. If you look at our netbacks, while I would imagine of your coverage list, you probably have some of the highest netbacks there is because we have forward sales in Canada. We’re actually forward selling and looking into the business for ’25 today as well. So that’s at times been a little below, but we’re winning with the hedging today. It’s not really hedging, it’s forward sales of molecules. They’re not adjusted for market. So you have to look in the back of the filing here today to see that. And that puts us in a — we don’t get the $0.50 ACO too much. We have differentiation in forward sales, and we’re at a different level. I think based on [indiscernible] we’re probably in pretty good shape on gas action.

Neil Mehta: Thank you, sir. And then the follow-up is just you alluded to Terra Nova. I recognize its smaller in the context of your portfolio and then you’re not the [indiscernible] operator here, but just your perspective on as an owner, how far are we away from getting that to optimal operations?

Roger Jenkins: I’ll let Eric go upon on that. I’m too emotional about it, Neil.

Eric Hambly: Thanks, Roger. We’re a bit frustrated with the operators performance in the second quarter. You can see it had a fairly significant impact to us in underperforming second quarter oil at Terra Nova. We are an 18% working interest owner in that with Suncor and Synovus, obviously having large ownership. We work with the operator and offer assistance and guidance to the extent we can as a non-operated partner. I feel that they have continued to make improvement, and we’re expecting that ultimately they will get through their larger than expected downtime issues and have steady operations. And later this year, we ought to see a 6,000 barrel a day net to us type production rate. So I’m confident they’ll get there, just a little slower than we’d like.

Neil Mehta: Thanks, Eric. Thanks, Roger.

Roger Jenkins: Thank you, Neil. Good talking to you. Take care.

Operator: The next question comes from Carlos Escalante from Wolfe Research. Please go ahead.

Roger Jenkins: Good morning, Carlos.

Carlos Escalante: Hey. Good morning, Roger and team. How are you guys doing?

Roger Jenkins: Doing great.

Carlos Escalante: I guess I’d like to start out my question with the shift on your Murphy 3.0 framework into the current quarter. You cited the 50% of adjusted free cash allocated to share buybacks and potential dividend increases. And I wonder and curious about how do you think about specifically the latter part of that, of that for the framework? What’s your dividend growth policy now that you’ve entered Murphy 3.0 earlier? And does one work at the expense of the other? And I guess just generally, how are you managing between buyback and dividend growth at this point of where you are?

Roger Jenkins: Thank you for that question. Very good question. If you really want — what I see in this is when you build these frameworks, we say primarily buyback and dividend increases, that would be a one-off dividend or a change in dividend policy, I can tell you today that the focus of this Murphy 3.0 is buybacks. We have been a long-term dividend player my entire life. Since 1961, we’ve been paying a dividend, returned billions of dollars to shareholders through dividend. So — and if you look at our framework, which I’m sure you’re familiar, you back out dividends underneath to get to the formula for our adjusted free cash flow that’s shared in this slide and in numerous slides and publications. So we see that as a difference.

We have a typical dividend. We’re trying to increase our dividend every year. And we see the minimum of 50% of adjusted free cash flow to really be focused on buybacks at this time and not about changing our dividend policy. So every year at the beginning of the year, we will be increasing our dividend hopefully, in this type of price regime, this type of business regime that we’re in. We want to be a dividend increaser, and then we’ll be using buybacks. And we want to be a company that’s ever increasing dividend per share, cash flow per share, and when we do that, we’ll be a successful company. And that’s when we use the buyback of stock to ever increase our EPS, our cash flow per share, and then increasing our dividend per share. But it is stated in that framework, dividend increases, but make no mistake, this is a buyback focus for our management team right now and will be for a while.

Carlos Escalante: Awesome. Thank you for that answer. And then on my second question, I’d like to ask you and perhaps Eric on what do you see as your sustaining capital being once you hit 2027, 2028, where you have clear line of sight on your project, and once you reach that 200,000 barrels of oil equivalent per day threshold? What do you see as your sustaining capital going forward at that point?

Roger Jenkins: Go ahead, Eric.

Eric Hambly: Sure. The way we think about our sort of longer term view when we get to that 210,000, 220,000 barrel a day range, 2027 on, is we anticipate reinvesting about 45% of our operating cash flow, and that may move around from year-to-year. If you have a $75 per barrel world, we anticipate that that would be something around a $1 billion a year of CapEx.

Carlos Escalante: Okay, thank you. Thank you, Eric. Thank you, Roger.

Roger Jenkins: One thing I might just add to that is when we build our long-range plans, we never assume that we have successful exploration. So if we do have material exploration success, we would likely see an increase in capital to fund that development. That’s one of the reasons why within our capital allocation framework, we’re using the part of our adjusted free cash flow that doesn’t go to share buyback to build cash on the balance sheet, so that in the future, we can use that cash to fund successful exploration. So if you think about our current business with zero exploration success, what I said earlier applies. If we make a massive discovery somewhere, then we probably increase our capital to fund that. But these things take a little bit of time, obviously.

Carlos Escalante: Thanks for the clarification, guys. Have a good one.

Roger Jenkins: Thank you. Appreciate it, Carl.

Operator: Your next question comes from Paul Cheng from Scotia Bank. Please go ahead.

Paul Cheng: Hi.

Roger Jenkins: Good morning, Paul. How you doing?

Paul Cheng: Hey, good morning. Two questions, may I? First, I think is for Eric. Eric, can you tell us what happened to the workover and that with the delay, because I thought the expense will be essentially done by the second quarter. And initially, I think you are targeting 68 and now you say actual spending was 65, but then the third quarter is another 35. So the pent up is going to be much higher than we initially thought. Can you tell us that what happened there? And also that can you talk about you still targeting by 2027, 210,000 to 220,000 barrel per day? If we look at the risk factor, where you see is the biggest risk in terms of achieving that. And second question, I think, is for Tom. It appears that there’s some one-off benefit in your U.S. operation, because I see a credit balance. You’re showing a credit in both G&A and other expense. Can you tell us what are those? Thank you.

Roger Jenkins: That’s three questions, Paul, but we’ll answer them all.

Paul Cheng: Thank you.

Roger Jenkins: Okay, I’ll get started talking about the Neidermeyer well. Just go back and have some context. We originally planned that as a fairly simple upper completion workover and it escalated into a sidetrack. And the sidetrack operation just took a little bit longer in the completion stage than we anticipated. This is a very high rate well, so missing out on 20 days or so of production from a high rate well impacts the production rate average for the quarter. It wasn’t anything particularly alarming or concerning. It’s just the operations took longer than our estimate. And in fact, if you look at our second quarter workover expense, it was very close to our guide. So we do see a little bit of the workover drifting into the third quarter.

We anticipated that Neidermeyer well being done, effectively spending money in the second quarter, and it drifted into the third quarter a little bit, which impacts a little bit the workover expense and the production. And then that impacts the following activity as well, the timing of the DC4 well. I think I addressed that first part of your question.

Paul Cheng: Sure. I think [indiscernible] is it always in the original plan that third quarter you have workover expense? Because maybe I got it wrong. I thought third quarter you’re not supposed to have workover expense before.

Eric Hambly: Yes, we believe we expect a third quarter workover expense. The timing may have moved just slightly with some cost drifting into the second quarter. But we can take a look at that. One thing I might do just to reiterate, if you look at our overall business, in the second quarter, our LOE per BOE was $15.09. If you exclude workovers, we were $10.77. In the second half of this year, we expect our operating expenses to drip down into the $11 to $13 per BOE range, with production volumes higher from our onshore business for the rest of the year, and also the Gulf of Mexico workover program wrapping up.

Paul Cheng: Thank you.

Eric Hambly: If you give me a second here, I can talk a little bit about your question around the long-term production rate. The things in our business that cause us to have variability of our range are primarily non-operated activity in our offshore business and exactly predicting correctly the rates of new wells to come online. Those are the main drivers for our production range. The other thing that has become a little bit challenging to predict, and we’ve tried to do the best we can, is our Montney volumes are pretty large, and the effect of royalty variation driven by gas prices can swing the BOEs quite a bit. I do want to point out that the overall royalty in the money is very, very low. So they do move around on us a little bit and that affects our range. It’s one of the reasons we communicated production range.

Paul Cheng: Okay, perfect. Thank you.

Tom Mireles: Okay. And Paul, I just wanted to make sure I understood your question. Was that in reference to the other income?

Paul Cheng: No. When I’m looking at your press release, when you break down the result in the E&P by U.S., Canada, and then when I’m looking at the U.S. expense line item, your G&A is a small credit, like $3 million in self expenses and income. And then the other expense is a $25 million credit. So it seems very unusual, wondering that is that one-off what related to those.

Tom Mireles: We can’t find what you’re talking about, Paul, at this time.

Roger Jenkins: It might be something we can …

Tom Mireles: Our G&A is industry leading pretty much, very low. And I’m not sure, Paul, we’ll have to …

Roger Jenkins: Let’s dig into the [indiscernible].

Tom Mireles: Let’s dig into that and get with Kelly and call you back.

Paul Cheng: Okay. Will do. Thank you.

Roger Jenkins: Great. Thanks, Paul. Appreciate it.

Operator: The next question comes from Leo Mariani from ROTH. Please go ahead.

Roger Jenkins: Hey, Leo. Good morning.

Leo Mariani: Hey, good morning. I wanted to touch based on the Eagle Ford a little bit here. Kind of looking at your guide for the year, it looks like maybe that some of the Eagle Ford wells flipped into fourth quarter here, from prior quarters. Just wanted to get a sense of what was happening there. It sounds like it might be some maintenance-related issues. And then, as a result, when do we expect Eagle Ford production to peak for the year? Is that going to be in 3Q or 4Q as you all see it here.

Eric Hambly: Okay, thanks very much, Leo. Our operated well program, the Eagle Ford, has actually been delivering a little bit earlier than normal. We have had a little bit of minor change in our non-operated program, so the cadence overall of net wells may have just very slightly altered. I wouldn’t characterize the overall impact as negative at all. In fact, I think we’re, on average, delivering slightly ahead of schedule. So that combined with the well performance, exceeding expectations across most of our wells, and a little bit earlier timing, we’ve seen a little bit higher rates earlier than expected. Peak production for Eagle Ford, based on the timing of our well delivery will be in the third quarter and see a bit of decline heading into the fourth quarter.

Leo Mariani: Okay, that’s helpful. And then just with respect to LOE, you talked about LOE coming down in the second half of the year, which is nice to see. If I just take a step back and look at your overall LOE, it’s up quite a bit this year in 24 versus where you came in last year and it sounds like workovers is driving the majority of this at the end of the day. I just wanted to kind of get a sense as you look out over the next couple of years, I mean, do you think that workover activity on some of these gulf wells can be similar in the next few years or do you think this year was maybe more of a one-off with some heavier activity and that should come down in the next couple of years and perhaps your overall LOE will be dropping?

Eric Hambly: Yes, definitely our workover activity this year is an outlier, quite a significant outlier, and I expect to have very limited workover activity in our offshore business going forward. If you look at our second quarter of ’24, our LOE excluding workovers was $10.77. That compares to prior year second quarter of $10.32 and most of that difference which is pretty minor is driven by Terra Nova restarting. Terra Nova has a bit higher operating expense than our other fields, our other Gulf of Mexico fields, so it does drive a little bit of the variance, but again we’re talking about $0.30 or so.

Leo Mariani: Okay. Now that’s helpful. And then just in the Gulf, I know that you folks are still looking to do more work on Ocotillo as a non-op well, but it seems like this would be a Subsea tieback just given the size. Is there infrastructure nearby that you guys could tie that back to?

Eric Hambly: That’s correct. We don’t operate the well. Ocotillo operates the well, and we are working with the partner group there for a plan of development of the field and I anticipate that it’ll be tied back to a nearby facility operated by Oxy.

Leo Mariani: Okay. Thank you.

Operator: [Operator Instructions] Our next question comes from Charles Meade from Johnson Rice. Please go ahead.

Roger Jenkins: Good morning, Charles.

Charles Meade: Good morning, Roger to you and your whole team there. Roger, I want to go back to your comment earlier in the Q&A, I think when you said you have hellacious wells in Canada. And I’m wondering if you could give maybe a little more detail. It looks like you’ve had some great results in both the Kaybob and the Tupper. And I’m wondering, is that just a happy coincidence, or is there some overarching kind of unifying theme there?

Roger Jenkins: No, we’ve just been doing so well. If you go back to Eric’s commentary in the script, which was an hour ago, I guess, we have some of the top wells we’ve ever had. We continue to improve our fracking and our execution based on our 4 or 5-year now reorganization of one operating team in Houston and lessons learned between Eagle Ford and there, and just really been delivering some record wells. Tupper Main is an older part of Tupper that we got, oh, I might have got that 17 years ago. And we went in there and did some old fracking and development there, came back with a new — some incredible wells there, industry leading wells there. If you benchmark Murphy against all North American gas, lowest breakeven price there is, adjusted back to ACO, et cetera.

Just a good run of great wells in the Montney and Kaybob 2 is a place where we’ve been dormant. We wanted to go and drill some wells and take our new ideas and take our new fracking to Duvernay Shale and prove that we have another Catarina. It’s exactly like the Catarina, which is a major Eagle Ford area that’s drilled by many peers, many public peers, sought after acreage in the Eagle Ford. So, we have another Eagle Ford business in Duvernay that just makes $5 a barrel less of oil and much higher NGL. So these wells are very economic and it just proves up our long-term giant onshore business. We’re not a company run out of locations or opportunities to go along with all the opportunities we have in the ocean and our big Vietnam future with exploration and a big project there.

So just wanted to highlight that on Slide 12 shows that we’re the second best operator in Kaybob, and we haven’t put wells in the ground there in 3 or 4 years, and we’re one of the top operators on a productivity basis in the Montney. So that’s what I was getting at there, Charles.

Charles Meade: Thank you. Thanks for that, Roger.

Tom Mireles: Charles, just to add briefly, we took our learnings from our Eagle Ford completions and in 2023 had a fundamentally different completion style in our Montney, and we saw tremendous results. And we used that information and when we went in to do the Kaybob completions this year we made some adjustments for localizing it for Kaybob but the same type of benefits we saw in Tupper we applied in Kaybob. So really a completely optimized completion design there and we’re able to execute it even more efficiently on timing and cost and get exceptional well results and I expect to see those going forward to potentially have minor improvements as well.

Roger Jenkins: Hey, Charles, one more thing. I got the word of your founder, Mr. Johnson, this morning. Sorry about that. I’m thinking about you guys today. He was a legend, legend guy in [indiscernible].

Charles Meade: Roger, that is appreciated by me and by the whole firm. I feel comfortable saying that. Thank you. The follow-up, Roger, you referenced your opportunities in the ocean. I know this is kind of peering a little bit further ahead, but a question about Côte d’Ivoire. And I know that you guys are going to have to have a — or plan to submit a field development plan in 2025, but I saw also that you expect to get your new seismic — new seismic back later this year. And I’m curious if you could maybe offer any insight into what sort of decisions that new seismic will inform. And if maybe they have to bear on some of the reasons that pay on wasn’t initially developed. Maybe about whether it’s questions about reservoir connectivity or compartmentalization that you expect to resolve, or just maybe you can paint the bigger picture for us there with respect to the seismic.

Roger Jenkins: Thanks, Charles. Really good question. I think the big 3D seismic is going to connect us from the shore to ultra-deep water. Also bookended by two big discoveries by ENI on both the east and west of us in this description here. We have a prospect very near the marine, big stoic announcement by ENI, which is a different type situation because they’re right there with another prospect in the same situation. As to PON, PON is a good discovery. PON has a great amount of data. PON was properly delineated by the prior owners. What’s changed there is the gas market. What’s changed there is Côte d’Ivoire wanted to be an electric supplier to their neighbors. What’s changed there, rolling blackouts in Côte d’Ivoire, we hear, possibly, and they want to have gas and probably didn’t want the gas then.

It’s a gas field, rich gas with an oil rim, and we’re working with them and they want this done. They requested that we, Murphy, which operate, big things offshore from scratch, is our calling card, and that was their request. So, the gas market’s changed. There’s not a compartmentalization or subsurface concern with PON at all. It is the change in market and we bring to bear our low-cost, fast development ability. That’s the reason we got to blocks. And that’s why we’re an alternative to supermajors in that type of exploration around the world. And that’s how we’ve been very successful internationally. And because things are important to us and are not as important to a supermajor because they have many, many opportunities. Let’s come up with a high-level of what’s going on there, Charles.

Charles Meade: That’s good detail. Thank you, Roger.

Roger Jenkins: Thank you. Take care.

Operator: Our final question comes from Josh Silverstein from UBS. Please go ahead.

Josh Silverstein: Good morning, guys.

Roger Jenkins: Hey, Josh.

Josh Silverstein: I just wonder, if I could follow-up on some of the questions — good morning — on the Montney. You guys have a deep resource space. You mentioned you’re kind of up against the plant capacity there. What is the next phase for that asset look like? Do you build some additional capacity up there just to bring forward some of the inventory that you have or is this kind of just flat at the capacity level for the foreseeable future. Thanks.

Eric Hambly: Okay. Yes, thanks, Josh. We’re really pleased with the performance we’ve had here in the Montney and able to execute on our multiyear plan of building production while generating free cash flow in that asset. We are up against capacity. We anticipate over the coming years to allocate capital to effectively keep that plant full or just under full. And for the near-term, that’s what we expect to do. If we were to consider a significant growth in production there, we would need to commit to an expansion of the plant and also additional pipeline capacity. And from a decision to do that to being online is approximately a 3-year process from a permitting, engineering, construction, commissioning type of cycle. And so it’s not an easy flip of switch and suddenly have a lot more.

We do evaluate the potential of expanding the plants and increasing the rate there. Since we recognize that we have such a large resource with so many decades of remaining gas, bringing that value forward is something that we consider, we model, we evaluate. If we decide to do it, it’ll be pretty well signaled since there’s a 3-year timeline on it. We are also very conscious of the fact that we’re producing half of BCF in a 17 BCF market. So if we added half of BCF, it would be a significant increase to what is happening in the ACO market. And we’re sort of kind of watch a little bit on the sidelines of what happens with LNG capacity. And as that grows with takeaway that’s been different than what we’ve seen in the past to a totally different market, that perhaps ACO strengthens and additional half a BCF of volumes would be supported by reasonable ACO prices.

So we’re sort of carefully watching and evaluating that, and it’s something we could do. We also may have a possibility in the future of participating in LNG opportunity through selling our gas to some potential partners that are involved in the Phase II of LNG Canada, if that’s something that is of interest to them.

Josh Silverstein: That’s helpful. And then maybe just on the balance sheet, return to capital framework, I’m curious what you think the kind of base level of cash is that you want to hold? I mean, even if you’re still at that 50% of free cash flow level, it goes to the buybacks, you can run scenarios in which you get to basically a zero net debt position in 2026. Do you want to continue to build that cash relative to the $300 million, $400 million that you guys have had beforehand, or is that kind of a comfort level for you guys around that. Thanks.

Tom Mireles: All right. Thanks, Josh. I’ll give you a little color on that. Our base level cash to run our business, we do try to maintain roughly $325 million, $350 million just for the needs that we have around the corporation. As we move past our debt target, once we get to a $1 billion, and we do start putting more cash on the balance sheet, that’ll give us more flexibility, and we’ll have to see where we are a few years down the road. Does it lead us to more debt reduction? Do we have exploration success that we can fund so that’s — or additional buybacks. So those are the types of options we’d be looking at, at that time. We look forward to getting to that point. We think we’re just a few quarters away from our pushing to the right into 2025 on our debt target. But at that point, when we start accumulating more cash, then we’ll make those decisions then.

Josh Silverstein: Thanks, guys.

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

Roger Jenkins: Thanks, everyone, for calling in today. We had a good call, had a lot of good questions. We appreciate those. Kelly and Megan and their team standing by to help our investors with further clarifications. And as usual, our management team stands by to respond to investors and our analysts. So take care and have a great day and see you in another quarter. Thanks.

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