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spk06: like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
spk00: Thank you, Operator, and 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 Morales, Executive Vice President and Chief Financial Officer. Please refer to the informational slides we have 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 interest in the Gulf of Mexico. Slide two. 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?
spk11: Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today on slide three. I'd like to reiterate our corporate priorities of deliver, 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 Loc De 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. Turned to Vietnam, we're preparing to spud the first of two operated exploration wells in the third quarter. Looking into 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, our 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 four. 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 two 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 reduced 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 EMP. On slide five, 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 our realized price of more than $81 per barrel, while our realized NGL pricing was nearly 22 per barrel, and our nat gas was $1.45 per thousand cubic feet. Overall, we generated $746 million of revenue per quarter, excluding NCI. I'll now turn the call over to our CFO, Tom Morales, for an update on our financial results. Tom?
spk13: Thank you, Roger, and good morning, everyone. Slide six, Murphy reported $128 million of net income in the second quarter, or 83 cents per diluted share, and $124 million of adjusted net income, or 81 cents 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. And we now have 150 million shares outstanding. I look forward to see what we will accomplish with the enhanced shareholder framework returns as part of MRFW 3.0. Slide 7. Murphy maintained strong liquidity with $1.1 billion available as of June 30th. 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 30th, we had $1.28 billion of long-term debt outstanding with our next maturity over three years away in December 2027. slide eight our sixth 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 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. Good morning.
spk14: Slide 10. Murphy produced 28,000 barrels of oil equivalent per day in the second quarter from the Eagleford 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 Katarina and four gross non-operated wells in Tilden during the quarter. We're on track to bring on five operated and three gross non-operated wells in Tilden in the third quarter. Our 2024 Katarina 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, five of our 2024 wells are among Murphy's top 20 Tupper-Monte wells based on IP30 rates. Slide 12. In the second quarter, our KBOB 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 K-Bob 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 Caterina wells in the Eagleford Shale, and I look forward to seeing further results. Flight 13. Mercury 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 number four well and non-operated Lucius number 11. We also drilled the operated Mormont number three well, which is on track to come online in the third quarter. In offshore Canada, we produced an average of 8,000 barrels of oil equivalent per day with 100% oil. Non-operated Terranova 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 Niedermeyer No. 1 sidetrack well, while our operating partner completed the Kodiak No. 3 well workover. The operated Dalmatian number two 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, total $68 million for the second quarter, which included the cost of the Niedermeyer 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 de 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 the discovery at the non-operated Ocotillo number one 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 number one exploration well and encountered non-commercial hydrocarbons. Our operating partner plugged and abandoned the well. Slide 18. We're preparing to begin our Vietnam exploration program, and we plan to spud the Hai Su Vong exploration well in block 15-17 late in the third quarter. The rig will then move to drill the Loc 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 pond discovery, Murphy remains on track to submit a fuel development plan by year-end 2025. Slide 21. For the third quarter of 2024, we forecast total production of 181,500 to 189,500 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 of 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 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 Plan Niedermeyer No. 1 sidetrack well delayed the rig from commencing the Dalmatian well workover. We also maintain our accrued CapEx range of $920 million to $1.02 billion, excluding NCI.
spk11: And with that, I will turn it back to Roger. 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 to 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. It set us up for an exciting second half of the year. Most importantly, Murphy is 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 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'll turn it back over to our operator and look forward to your questions this morning.
spk06: Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the 1 on your touchtone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the two. If you are using a speakerphone, please lift the headset before pressing any keys. One moment, please, for your first question. Your first question comes from Neil Dignam, Trust Securities. Please go ahead.
spk12: Morning, Roger, and nice quarter. My first question is 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 potential shareholder return and you always see a lot of interesting acquisitions, creative potential acquisitions, is this just simply a return exercise? How do you decide between these two?
spk11: Thank you so much, Neil. One thing about when our board meets, we have a lot of ownership on our board, probably second of all of EMP. So it's a little bit of a different matter when we meet about returns. This was my idea to do this. It wasn't from investor outreach. I believe our framework was successful. We just started benchmarking with Tom and his team. What 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 pricing dislocation this year and our equity pricing, and we're 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, Neil, about this, and I can't emphasize it enough, from the original framework disclosure two 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 and would pull back on the cash flow we have. And debt of that could be associated with that as well. And 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. It 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 those possibilities, people will say, well, You may not ever reach a billion. You may do this. You may do that. But now we closed that off and moved it.
spk12: Now, 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 just talk about just oil production for remainder of the year, how that's impacted both offshore and onshore? Thank you.
spk11: Well, Eric's going to handle the offshore and onshore questions today. Go ahead, Eric. Okay, thanks very much.
spk14: Neil, 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 well as 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 Niedermeyer number one well that we did a sidetrack on took a little bit longer to complete that operation. So it came online slightly later than our earlier guidance. And because the rig that was on that well is moved to the Dalmatian PC4 number two 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 kind of 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 DC-4 number one 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 partially offset by decline in our onshore business, which is typical since we have a very limited number of wells to come online the rest of the year in our onshore business. Perfect. Thank you all.
spk11: Also, Neil, I 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. And I There's no hurricanes. It would be way higher. That's right.
spk03: Great point. Thank you, Roger. Thank you, Neil. Take care.
spk06: Your next question comes from Arun J. Arun from J.P. Morgan. Please go ahead.
spk10: Good morning. 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 spreading the first well by the end of the before the end of the third quarter, but maybe just give an update on on on that program.
spk11: I'll have high level air digging a bit to detail. So we have a big project going there, 100 million barrel field that we're developing. We've been in Vietnam for a while and we were brought to Vietnam by their government because we were very successful. and a shallow water business in Malaysia, which both Eric and Tom ran parts 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 a couple of what else is about to go here.
spk14: 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 spot our well late in the third quarter. The first well that we'll start drilling will be on Block 15217, the Hai Su Vong prospect, where we're targeting a mean to upward volume of 170 to 430 million barrels. It's a very nice looking prospect, sizable prospect that'll test the same type of geology as our Lac de Vente 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 de Hong prospect. And that's targeting a 65 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.
spk10: Great. My follow-up is just on slide 22. You highlight the three-year period program which will deliver 5% growth CAGR to 195 MBOE per day at 95,000 barrels of BOEs offshore. Can you help us think about some of the growth drivers, Roger, in 2025? Obviously, 2026, you'll start getting some volumes in Vietnam, but just help us think about some of the growth drivers next year.
spk11: 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 Cleesey-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 will be flowing for the full year. We're hopeful that Terranova 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 three-year average deal, not necessarily 25. But we have many opportunities to be on and many opportunities that will flow for the whole year as you put on these wells. And they come in at a pretty high rate. So that's how that's going to march upward on that room.
spk03: Thank you, sir. Oh, thank you.
spk06: Your next question comes from Neil Mehta from Goldman Sachs. Please go ahead.
spk04: Good morning. Good morning, sir. Thanks for taking the time. I had a couple Canada questions for you, if you will. I guess the first is, we're in a challenging environment for eight. I think there's an interesting multi-year outlook for Western Canadian gas prices from where we are here, but And just your perspective on, you know, the way some of the U.S. gas producers are holding back molecules until we get into a better environment. Does it make sense to change the cadence of your production profile to monetize into a better price environment?
spk11: Thank you for that, Neil. Great question. We're a little different than the big gas-only players in the U.S. We have a plant and an infrastructure that can only handle $500 million a day, so it's not an enormous figure. 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 a C dollar type of exchange. So we have very extremely low breakeven prices. We have hellacious wells. We have commitments to our pipelines and to this plant. And so far, economically, it's shown us to want to do that. And we I see a future there with LNG Canada over a long haul. We have relationships that are key to us and 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 break-even. 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, Neil. So 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 net guest netbacks there is because we have forward sales in Canada, and 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 that are 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 50 cent ACO too much. We have differentiation and forward sales and we're at a different level, I think, based on US fairs, probably pretty good shape on gas actually.
spk04: Thank you, sir. And then the follow-up is just you alluded to Terra Nova. I recognize it's smaller in the context of your portfolio, and then you're not the operator here, but just your perspective on as an owner, you know, how far are we away from getting that to optimal operations?
spk11: I'll let Eric opine on that. I'm too emotional about it, Neil. Thanks, Roger.
spk14: We're a bit frustrated with the operator's performance in the second quarter. You can see it had a fairly significant impact to us in underperforming second quarter oil at Terranova. 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 and 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. It's just a little slower than we'd like.
spk03: Thanks, Eric. Thanks, Roger. No, thank you, Neil. Good talking to you. Take care.
spk06: Your next question comes from Carlos Escalante from Wolf Research. Please go ahead.
spk08: Good morning, Carlos. Good morning, Roger and team. How are you guys doing? Doing great. I guess I'd like to start out my question with the shift on your MER 3.0 framework into the current quarter. 50% of adjusted free cash were 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 for the framework? What's your dividend growth policy now that you've entered MER 3.0 earlier? And does one work at the expense of the other? I guess just generally how do you manage in between buybacks and dividend growth at this point of where you are?
spk11: Thank you for that question. Very good question. If you really want me to, what I see in this is when you build these frameworks, you know, 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, in 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 that 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 or 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 so we're going to 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.
spk08: Awesome. Thank you for that answer. And then on my second question, I'd like to ask you and then perhaps Eric 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?
spk14: Go ahead, Eric. Sure. The way we think about our sort of longer-term view when we get to that 210, 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 billion dollars a year of CapEx.
spk02: Okay. Thank you. Thank you.
spk14: One thing I might just 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 kind of things take a little bit of time, obviously.
spk02: Thanks for the clarification, guys. Have a good one. Thank you.
spk03: Appreciate the call.
spk06: Your next question comes from Paul Chang from Scotiabank. Please go ahead.
spk09: Good morning, Paul. How are you doing? Hey, good morning. Two questions, may I? First, I think it's for Eric. Eric, can you tell us that what happened to the work over and that with the delay and 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 end 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're still targeting by 2027, 210 to 220,000 bill 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 balance. in both G and A and the other expense. Can you tell us what are those? Thank you.
spk11: That's three questions, Paul, but we'll answer them all.
spk14: Okay, I'll get started talking about the Niedermeyer 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. 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 Niedermeyer 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 DC-4 well. I think I addressed that first part of your question.
spk09: Sure, because I thought, is it always in the original plan that third quarter you have work over expense because maybe I got it wrong. I thought third quarter, you're not supposed to have work over expense before.
spk14: Yeah, we believe we expect a third quarter work over 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 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. Thank you. If you give me a second here, I'll 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 montany 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 communicate at production range.
spk09: Okay, perfect. Thank you.
spk13: Okay, and Paul, I just wanted to make sure I understood your question. Was that in reference to the other income?
spk09: No, when I'm looking at in 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 25 million So it seems very unusual. Wondering that is that one off what we made to those.
spk11: We can't find what you're talking about, Paul, at this time. It might be something we can. Our GNA is industry leading pretty much, very low. And I'm not sure, Paul. We'll have to. Let's dig into that. Let's dig into that and get with Kelly and call you back.
spk09: Okay, we do. Thank you.
spk11: Okay, thanks Paul, appreciate it.
spk06: Your next question comes from Leo Mariani from Roth. Please go ahead.
spk05: Hey Leo, good morning. Hey, good morning. Wanted to touch base on the Eagle Ford a little bit here. Kind of looking at your, you know, guide for the year, it looks like maybe that some of the Eagle Ford wells flipped into fourth quarter here, you know, 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, you know, 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?
spk14: 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. 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 Eagleford 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.
spk05: 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, you know, workovers is driving the majority of this at the end of the day. I just wanted to kind of get a sense, you know, as you look out over the next couple 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 years and perhaps your overall LOE will be dropping?
spk14: Yeah, definitely our work over activity this year is an outlier, quite a significant outlier. And I expect to have very limited work over activity in our offshore business going forward. If you look at our second quarter of 24, our LOE excluding work overs 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 operating Gulf Mexico fields. So it does drive a little bit of the variance. But again, we're talking about 30 cents or so.
spk05: Okay, now that's helpful. And then just in the Gulf, I know that you folks are still looking to, you know, do more work on Ocotillo. It's 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?
spk14: That's correct. We don't operate the well. Occidental 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 will be tied back to a nearby facility operated by Oxy.
spk02: OK, thank you.
spk06: Please press star followed by the one should you have a question. Our next question comes from Charles, made from Johnson Rice. Please go ahead.
spk11: Good morning, Charles.
spk07: 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 – both the KBOB and the Tupper. And I'm wondering, is that just a happy coincidence or is there some overarching kind of unifying theme there?
spk11: 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 four or five year now reorganization of one operating team in Houston and lessons learned between Eagleford and there, and just really been delivering some record wells. Tupper, Maine is an older part of Tupper that we got. Oh, I might've got that 17 years ago. And we went in there and did some old fracking and development there and came back with a new, some incredible wells there, industry leading wells there. If you benchmark Murphy against all North American gas, lowest break-even price there is, adjusted back to ACO, et cetera. Just a good run of great wells in the Montney, and K-Bob, too, 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 cat arena. It's exactly like the cat arena, which is a major Eagleford area that's drilled by many peers, many public peers, sought after acreage in the Eagleford. So we have another Eagleford 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 running out of locations or opportunities to go along with all the opportunities we have in the ocean and our big Vietnam future with exploration, a big project there. So just wanted to highlight that today on slide 12 shows that we're the second best operator in KBOB, and we haven't put wells in the ground there in three or four years. and we're one of the top operators on a productivity basis in the Montany. So that's what I was getting at there, Charles.
spk07: Thank you. Thanks for that, Roger.
spk14: 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 Montany and we saw tremendous results. And we used that information And when we went in to do the KBOB completions this year, we made some adjustments for localizing it for KBOB, but the same type of benefits we saw in Tupper we applied in KBOB. 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.
spk11: Hey, Charles, one more thing. I got the word of your founder, Mr. Johnson, this morning. Sorry about that. Thinking about you guys today, he was a legend guy in New Orleans.
spk07: 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 the Cote d'Ivoire. And I know that you guys are going to have to have a plan to submit a field development plan in 25, but it's also that you expect to get your 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... Maybe they have to bear on some of the reasons that Paon 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.
spk11: Thanks, Charles. Really good question. I think the big 3D seismic is going to connect us from the shore to ultra-deep water and We're 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 Maureen 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 Cote d'Ivoire wanting to be an electric supplier to their neighbors. What's changed there, rolling blackouts in Cote 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, you know, big things offshore from scratch, is our calling card. And that was their request. So the gas markets changed. There's not a compartmentalization or subsurface concern with pawn 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 the blocks. And that's why we're an alternative to super majors 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 super major because they have many, many opportunities. Let's come up with a high level of what's going on there, Charles.
spk07: That's good detail. Thank you, Roger.
spk03: Oh, thank you. Take care.
spk06: Our final question comes from Josh Silverstein from UBS. Please go ahead.
spk02: Good morning, guys.
spk13: I just wanted to follow up on some of the questions. Good morning. You guys have a deep resource space. You mentioned you're kind of up against the plant capacity there. What does 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 this capacity level for the foreseeable future? Thanks.
spk14: Okay. Yeah. Thanks, Josh. pleased with the performance we've had here in the Maundy and able to execute on our multi-year 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, 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 three-year process from a permitting engineering construction commissioning type of cycle and so it's not a easy flip a 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 three-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 going to 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 two of LNG Canada, if that's something that is of interest to them.
spk13: That's helpful. And then maybe just on the balance sheet and return of 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 beforehand, or is that kind of a comfort level for you guys around that? Thanks. All right. Thanks. 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, $350 million just for the needs that we have around the corporation. As we move past our debt target, once we get to a 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. Is it Does that lead us to more debt reduction? Do we have exploration success that we can fund? 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.
spk06: 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.
spk11: Thanks, everyone, for calling in today. Had a good call. Had a lot of good questions. We appreciate those. Kelly and Megan, 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.
spk06: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and we ask that you disconnect your lines.
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