Murphy Oil Corporation (NYSE:MUR) Q2 2023 Earnings Call Transcript August 3, 2023 Murphy Oil Corporation beats earnings expectations. Reported EPS is $0.79, expectations were $0.75. Operator: Hello and good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation’s Second Quarter 2023 Earnings Conference Call and Webcast. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions]. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Kelly, 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, President and Chief Executive Officer; along with Tom Mireles, Executive Vice President, Chief Financial Officer; and Eric Hambly, Executive Vice President, Operations. Please refer to the informational slides we placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today’s call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of Mexico. Slide 2. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995.
As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause the actual results to differ. For further discussion of risk factors, see Murphy’s 2022 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I will now turn the call over to Roger Jenkins. Roger? Roger Jenkins: Thank you, Kelly. Good morning, everyone, and thank you for listening to our call today. If we turn to Slide 3, Murphy continues to deliver strong value proposition. Our ongoing execution excellence ensures that we remain a long-term sustainable company. We operate safely with a focus on continual improvement in our carbon emissions intensity. Our offshore competitive advantage is reinforced with our significant recent project success at Khaleesi/Mormont Samurai fields in the Gulf of Mexico. Murphy also has a diverse exploration portfolio and recently expanded with our new country entry into Cote d’Ivoire. We continue to generate strong cash flow, and we have been able to more than double our long-standing dividend from 2021 as well as significantly reduced debt over the last 24 months. On to Slide 4. Our stated priorities of delever, execute, explore and return remain our focus as we advance through 2023. We’re in excellent shape to advance Murphy 2.0 or our capital allocation framework with a targeted debt reduction goal of $500 million in the second half of the year as well as stock buybacks. The goal of Murphy 2.0 will be enhanced by using proceeds from our noncore asset divestiture in Canada. We continue to execute our priorities operationally as production exceeds the upper end of production range due to strong well performance in the second quarter or the second quarter in a row rather, in addition to our highest oil production rate in two years. The team brought online a total of 27 operated onshore wells across the Eagle Ford Shale and Tupper Montney in the second quarter at or ahead of plan and also completed Gulf Mexico facility maintenance ahead of schedule. Additionally, I’m pleased that we received government approval for the lockdown field development plan in Vietnam this quarter. Regarding our exploration strategy in the second quarter, we initiated a new country entry into Cote d’Ivoire. We’re also progressing plans to resume drilling on the Murphy-operated Oso exploration well in the Gulf of Mexico late in the third quarter with consistent operational performance and decreasing CapEx for the rest of the year, free cash flow generate will support our strategy to return funds to shareholders through our capital allocation framework. On the Slide 5, a strong quarter for us. In the second quarter, we had 184,000 equivalents per day and exceeded guidance by over 6,000 barrel equivalents from a better-than-expected well performance, plus 1,400 barrels equivalent per day from lower realized Tupper Montney royalty rates. Oil production of 99,000 barrels equivalent today, which was some 5,000 barrels per day above guidance grew by 10% over the second quarter of 2022, reflecting production beats and our oil-weighted Eagle Ford Shale and Gulf of Mexico assets. We realized $73.54 per barrel for our oil, while our realized NGL price was $19 per barrel and nat gas for Murphy was $1.92 per 1,000 cubic feet for the quarter. Now I’m going to turn the call over to our CFO, Tom Mireles for an update on our financials and sustainability efforts. Tom Mireles: Thank you, Roger, and good morning, everyone. Slide six. Net income in the second quarter totaled $98 million or $0.62 per diluted share. Including after-tax adjustments, adjusted net income was $124 million or $0.79 per diluted share. These amounts were impacted by $116 million of exploration expense during the quarter, including noncontrolling interest. This was primarily comprised of $54 million net to Murphy in drybulk costs for the Chinook number 7 exploration well, as well as a $17 million write-off of the previously suspended Cholula exploration well and $10 million in seismic costs for the Cote d’Ivoire new country injury. Murphy’s strong operational performance generated cash from operations, including noncontrolling interest of $470 million. After accounting for net property additions and acquisitions, we had adjusted cash flow of $121 million. This amount reflects $28 million in total contingent consideration payments made during the second quarter, $25 million of which was related to the one-year anniversary of first oil at King’s Key. All of our obligations have now been fulfilled related to the two Gulf of Mexico acquisitions in 2018 and 2019. Slide seven. I’m pleased to say our fifth annual sustainability report was just released, which includes enhanced disclosures surrounding our actions towards reducing emissions intensity, improving water recycling, continued strong governance oversight and an ongoing focus to positively impact the communities around us. Of note, in 2022, we recorded our lowest emissions intensities for greenhouse gas, methane and flaring since 2013. We have also achieved our highest water recycling ratio in company history across our onshore assets. Lastly, we have received a number of awards and recognitions for our dedicated service to the communities as we continuously strive to make it better. With that, I will turn it over to Eric Hambly, our Executive Vice President of Operations, to discuss our operational update. Eric Hambly: Thank you, Tom, and good morning, everyone. Slide nine. In the Eagle Ford Shale, Murphy produced 35,000 barrels of oil equivalent per day in the second quarter with 89% liquids weighting. A total of 17 operated wells were brought online as planned across Catarina and Tilden, and we have seen them outperform expectations due to our optimized completion design. Of the 2 Tilden pads that began producing in the quarter, four wells are outperforming their pre-drill forecast by 100%, with the other four wells producing in line with forecast. Overall, these eight Tilden wells have an average IP30 of 1,200 barrels of oil equivalent per day with 85% oil. For the third quarter, we plan to bring online seven operated wells in Catarina and Tilden and two nonoperated wells in Tilden. Slide 10. Murphy produced 341 million cubic feet per day in the Tupper Montney and brought online 10 wells during the second quarter. Of that amount, seven were originally planned for the third quarter, but were brought online early. We applied our learnings from our Eagle Ford Shale completions design in the Tupper Montney this quarter on the most recent seven wells and through activities such as real-time frac optimization, we have seen incredible results. These wells are achieving some of the highest IP30 rates in Murphy history with all seven wells averaging approximately 17 million cubic feet per day. Even more encouraging, two wells have achieved a new Murphy IP30 record of more than 21 million cubic feet per day. We look forward to applying these learnings on the remaining well in 2023 and as we plan for our 2024 drilling program. Slide 11. We are excited to announce today, that we have signed a purchase and sale agreement to sell a noncore portion of our onshore Canadian assets to a private company. Under the terms of the agreement, the buyer will pay Murphy CAD 150 million at closing in an all-cash transaction, subject to customary closing adjustments and conditions. The transaction has a March 1, 2023 effective date, and we anticipate closing will occur in the third quarter of 2023. The assets to be divested include the Saxon and Simonette areas of Kaybob Duvernay, where Murphy holds a 70% working interest as operator, as well as Murphy’s 30% working interest in Placid Montney assets operated by Athabasca Oil Corporation. Also, included are batteries pipelines and the assumption of related processing and marketing contracts. The combined assets, currently produce 1,700 barrels of oil equivalent per day, NedlMurphy and consists of 39% oil. Net proved reserves were 5.3 million barrels of oil equivalent as of December 31, 2022, also included our 250 gross drilling locations or 138 net locations across the two areas. After closing, Murphy will have approximately 488 gross drilling locations with an average 75% oil weighting remaining in the Kaybob Duvernay, all of which are operated with a 70% working interest. We will have no remaining position in the Placid Montney. Slide 13. We continue to see outstanding performance from our offshore wells, particularly at Khaleesi, Mormont and Samurai. Combined, our offshore assets produced 86,000 barrels of oil equivalent per day in the second quarter with 80% oil weighting and production 3% above guidance. Looking to our tieback projects in the third quarter, we will focus on completing the Murphy-operated Dalmatian number one well before moving to spud the Marmalard number three development well late in the quarter. Additionally, our operating partners continue to progress to St. Malo Waterflood and Terra Nova projects. Slide 14. Murphy recently received final approval on our field development plan for the Lac Da Fang field in Block 15, 105 in Vietnam. This is a discovered field with multiple penetrations in well tests, and we estimate 80 million to 100 million barrels of oil equivalent gross resource. Murphy will continue to advance the field development plan ahead of final project sanctioning later this year. We also look forward to additional future exploration within this block as there are multiple prospects that we find attractive. And with that, I will turn it back to Roger. Roger Jenkins: Thank you, Eric. On slide 16, we recently expanded our exploration focus by signing production sharing contracts to secure working interest as operator in five exploration blocks for new country entry into Cote d’Ivoire. We’ll initially hold 85% to 90% working interest with PETROCI holding the remaining working interest in each block. It’s important to note we have no well commitments in the initial two-year exploration phase, which provides us the time to conduct proper geophysical studies over the blocks. Cote d’Ivoire is adjacent to Ghana, which has a large successful Jubilee field as well as a sizable pan development in comparison on the eastern side of Cote d’Ivoire is a discovery called Baleine, which is operated by Eni and considered the largest discovery in the country as well as one of the largest discoveries in industry in recent years. Shifting West to our acreage in CI-102 as a shallow water historic type opportunities and just to the south in Block CI-531, we have a look like structure to the Baleine field operated by Eni, which is a carbonate discovery, which is a different type of opportunity for Murphy. In CI-103, we hold a long-term undeveloped discovery called Paon, which is appraised with multiple wells by previous operator as well as the agreement on the block, we’ve committed to submitting a viable field development plan by the end of 2025. Lastly, in CI-709, which is a large block with multiple geologic features similar to Jubilee. Overall, this is a very exciting new entry for Murphy. We look forward to the exploration opportunities and will highlight our unique operational abilities. On slide 17, we completed the drilling Chinook number 7 exploration well in the Gulf of Mexico during the quarter and encountered non-commercial hydrocarbons. Murphy plugged and abandoned the well and expensed $54 million of net dryhole whole costs in the quarter. Late in the third quarter, we plan to resume drilling of the Murphy-operated OSO exploration well in Gulf of Mexico after temporary suspending drilling earlier this year. On slide 19, for the quarter, we forecast production of 188,000 to 196,000 barrels equivalent per day with 99,000 barrels of oil per day. This range includes assumed Gulf of Mexico storm downtime of some 4,600 barrels equivalent per day as well as a total operated planned downtime of 2,900 barrels of oil equivalent per day. Also in the third quarter, we forecast accrued CapEx of $215 million, excluding acquisition-related costs. For the full year 2023, we are raising our production guidance to 180,000 to 186,000 barrels equivalent per day, which represents a 3,500 barrel per day increase to the midpoint. We forecast producing 53% oil and 59% liquids in this range. Additionally, we are tightening our accrued CapEx guidance with a new range of $950 million to $1.025 billion, excluding $45 million of acquisition-related costs. We remain confident in delivering an 8% oil volume growth and 10% production growth over full year 2022 with lower capital spending. On slide 20, Murphy has a multi-tier capital allocation framework that allows for additional shareholder returns beyond the quarterly dividend, while advancing toward a long-term debt target of $1 billion. Our Board has authorized an initial $300 million share repurchase program, allowing Murphy to repurchase shares through a variety of methods with no time limit. As of today, we’ve not yet executed any repurchases under this authorization. Since we first announced the capital allocation framework one year ago, I’m pleased that we returned an additional $15 million annually to shareholders through the quarterly dividend increase of $0.0275 per share as well as paid down nearly $500 million of debt. I look forward to progressing Murphy 2.0 with the proceeds on the transaction we announced today and further rewarding our long-term shareholders in the quarters to come. On Slide 21, as we continue our strategy to delever, execute explore and return, we remain focused on reducing debt with adjusted free cash flow. Approximately 40% of operating cash flow is forecast to be invested annually through 2025. We forecast maintaining an average 55% oil weighting with production averaged 195,000 equivalents per day, representing a combined annual growth rate of 8% through 2025, while also supporting a targeted exploration program. As part of this plan, offshore production will maintain at an average of 90,000 to 100,000 barrels equivalent per day. Longer term, we’re focused on maintaining sustainable business, targeting investment-grade metrics. Average annual production is forecasted approximately 210,000 barrels equivalent per day with 53% oil weighting. Our ongoing reinvestment of approximately 40% of operating cash flow results in ample adjusted free cash flow generation, which we used to fund further debt reductions in our capital allocation framework and enhance total shareholder returns in addition of funding high-returning investment opportunities. On Slide 22, looking at the second half of the year with our capital program declining, upcoming proceeds from our onshore Canadian diversiture announced today and current oil prices, we’re focused on achieving our $500 million, debt reduction goal and enhancing shareholder returns through buybacks as we advance 2.0 of our capital allocation framework. We look to continue our high-quality execution ability as we complete our onshore well delivery program for the year while also improving base production declines and maintaining high uptime across our portfolio. Ultimately, it’s important to send everyone home at the end of the day, and we’re able to achieve this through a strong ongoing safety culture. We have one remaining operated exploration well in 2023 program, and we’ll resume Oso drilling late in the third quarter. Lastly, I’m proud of our two recent announcements of receiving the Lac Da Vang development plan approval and signing new PSCs in Cote d’Ivoire. We have a long history of successfully executing projects while delivering on our free cash flow conventional business, and these opportunities will add to our longevity, both in the near term with Vietnam and longer with exploring and possible development plan off the West Coast of Africa. I’ve to close our call today by thanking our outstanding employees, this great quarter we had and their ongoing dedication of Murphy. It takes every level of the organization to achieve this success, and I appreciate every one of you. And now I’ll turn it back to the operator for our calls, and I appreciate you listening to our prepared remarks this morning. See also 12 Best Biotech ETFs To Buy and 15 States That Produce the Most Corn.
Operator: Thank you, sir. Ladies and gentlemen, we will now conduct the question-and-answer session. [Operator Instructions] The first question we have in the queue today it’s going to be coming from Bert [indiscernible] Q – Unidentified Analyst: Hi, good morning. Roger and team. Yes, go ahead, operator. Operator: Go ahead, Charles [ph]. [indiscernible] go ahead Q – Unidentified Analyst: All right. Thank you. Good morning, guys. I just want to — First of all, it was stronger free cash flow than we were expecting in 2Q. Just trying to square away where the rest of the year the calculation works. So is there still, I think I did the math right, maybe $15 million of acquisitions for the international side and then maybe $10 million for the Gulf of Mexico lease sale. And I think all the contingency payments are gone, but is there any other math in the background that we should be netting against our free cash flow estimates to determine the Murphy 2.0 framework? Roger Jenkins: Thanks for that question. Really good question. I think the way to feel about to show that is today, we’ve announced that our capital for the year is tightening range. And then on top of that, we have $45 million of additional new business, if you will, that were never in our plans such as achieving field development, Vietnam and signing the new blocks in Cote d’Ivoire, which includes seismic and other activity. So that will be on top of the range of our CapEx is the way to think about it, to take what we spent to date and have that remaining for the rest of the year, of which about a third to a high for that money has been spent so far on the acquisition expenses, and that’s the way to think about the total cash flow for the year. We really don’t break out the Cote d’Ivoire in the Vietnam due to privacy around what we have, we’re really proud of the deals that we have. So we’re not breaking out what’s what. But that’s the way to think about our capital spending for the rest of the year. Q – Unidentified Analyst: Okay. And does the Canadian divestiture count towards that calculation or just moves closer to kind of the Murphy 2.0, 3.0 situation? Roger Jenkins: Thank you for that. That’s a really good point. How we’re assuming this year is we’re bringing that money in. It’s in C dollars, we convert it to US dollars, transported home when needed, and it too will be shared 75-25 through debt and pay down debt and buyback and just come in. If you think about it, really what’s happening here is if you take the acquisitions and add on to our new midpoint, the Canadian proceeds easily handles that, and we’re back square in our debt reduction goal and our debt down. Our debt paydown goal as well as buying back stock, and we’re very excited about that and lower capital spending in the rest of the year. So, it’s in the framework, if you will, as free cash flow to allow for the extra money spent on non-planned new businesses in African Vietnam. And so that’s how we’re thinking about it. Q – Unidentified Analyst: That’s a great way to think about it. And then just a follow-up on the Canadian sale. Is that all that you guys are looking to sell? Was that opportunistic, or is there any other parts of your maybe non-core positions that you’re looking to let go? Roger Jenkins: Again, a really good question. I’m glad you pointed that out early in the call. We have a lot of assets. We have a lot of very high-quality onshore oil-weighted assets and also an incredible Montney position you see from Eric’s comments today how great the Montney is doing with 21 million IP 30s this competes with any gas play in North America. On the oil side, we all know that we have a lower volume growth business in onshore, and we have ample locations. And this was also a very good offer. It’s a very good offer if you think about a little over US$100 million, taking away only 5 million barrels of reserves. If you think about the production today at only 39% oil, you think about how much per flowing barrel that is, how much for acre it is, how much locations. So it’s an incredible offer that we needed to take, because we still have 488 locations to go in Canada, and they’re all weighted at 70% oil, which is just slightly below the Eagle Ford, but the NGL in that region is double the price of NGL in Texas. So these wells are going to be drilled in the 2040s. And we sold them for a really good price to an operator that wants to invest there. We’re very happy about it, but we’re not for sale there. But as we have aging non-core locations and people want to really pay that for us, we’ll take that money and transpose it into things such as think about Code d’Ivore. We have unreal cost entry into many blocks with new opportunities, including a very large opportunity. We have a possible development in Vietnam. I mean a development in Cote d’Ivoire and in Vietnam we have a development and exploration there. So able to move our business around and take long used onshore locations forward in cash, investing is something where we have great competitive advantage in offshore execution. Q – Unidentified Analyst: That’s a great update Roger. Thanks. Roger Jenkins: Thank you. Operator: The next question in the queue comes from Tim Rezvan with KeyBanc. Your line is open.
Tim Rezvan: Good morning, everybody. Thank you for taking my question. I was hoping to dig in a little deeper on Vietnam. I was wondering if you could provide more specificity on the steps towards sanctioning by year-end. And then if you can maybe give a big picture overview where you stand today, how you think this asset could possibly hit first production in 2025 and how we can expect to ramp? Just sort of updated thoughts based on the latest news. Thanks. Roger Jenkins: Thank you for that question, Tim, and thanks for new coverage on Murphy and calling into our call today. I appreciate that. Vietnam has been around our business for a long time. We have through COVID and through our reduction in capital, have some things has been on the sidelines a bit. The key change here is that PetroVietnam, which is also our partner decided to approve our field development plan, which has been submitted for sometime. We see this as a, 80 million to 100 million barrel type opportunity. It’s been well tested. It’s very well organized and planned. We have a detailed field development plan that we’ve had for a while. So what’s going on now is we would re-bid all the services there, such as drilling and building of the facilities and then seek to check the economics of that, again, reaffirm that, go to our Board, but that sometimes either in October or December meetings, then we would probably not have first oil there to 26. We want to work the project into really late early 25, if you will, so we can have ample returns to our shareholders through our framework, which is a key, key focus for us. And it’s not a very expensive development or a difficult development, something we have a long history of doing in shallow-water Malaysia where we built a large business. Also key in Vietnam as we have two very nice exploration opportunities, I actually have more than that, but we’re drilling probably two next year that can hence and make this into a business. Our goal is to make this into a 30,000 to 40,000 barrel a day business net to Murphy in Vietnam. We should have the exploration, lower risk opportunities in the field to do that and looking forward to executing on that. Tim Rezvan: Okay. I appreciate that context. That’s helpful. And then, if we could take a follow-up on the Murphy 2.0 framework. You have a 2025 notes callable par in mid-August. And I know there’s, some asset sales, not sure on the repatriation status of that. But as you think about retiring debt, how do you measure getting debt retired as soon as possible versus waiting to call that at par because your 2027 and 2028 have our callable site premiums out over the next kind of one to two years. So just curious on your thoughts on when and how you will look to officially get that debt retired. Thank you. Roger Jenkins: Yeah. Tim, I’m going to let Tom, our CFO, handle that for you. Tom Mireles: Yeah. Sure. Thanks, Roger. Thanks, Tim. Yeah, generally, the way we think about it, we balance all those factors, whether it’s the maturity date or how the notes are trading and decide are we going to go with calling or maybe open market or tendering. As we look at getting into 2.0 second half of this year, as you point out, we’ve got those 25. Those will be able to call at par just later this month. And so we’ll probably focus on those initially. But if you look at the overall goal of us getting to $1 billion, that’s another $800 million of debt reduction. And between the 25 and 27, that’s about that amount, that’s callable today, 25% is being close to calling them that par soon. So that’s how we’re thinking about it. So we think to get to our $1 billion target, we can take that path. Tim Rezvan: Okay, I appreciate the response. Thanks. Tom Mireles: Sure. Operator: Thank you. And the next question in the queue comes from Devin McDermott with Morgan Stanley. Please proceed. Devin McDermott: Hi Good morning. Thanks for taking… Roger Jenkins: Hey Devin. Good morning. Thanks Devin. Devin McDermott: Hi Roger. So I wanted to ask on some of the exploration opportunities first and specifically on Côte d’Ivoire. So it seems like there’s two kind of parallel processes here. One is the Paon discovery and submitting a development plan for that and the second would be the seismic acquisition and evaluation of that for the remaining blocks. Could you just walk us through each of those? So for the development plan, what you would need to see ultimately for development to proceed there? And then similarly, the timeline of the seismic acquisition and when you think about potentially, drilling any exploration wells on the other blocks there? Roger Jenkins: Thanks so much, Devin, for that focus on that. It’s a very good opportunity for us to kind of this opportunity fits a real bill for us and need for more exploration, exploration near success, different play types. Then we have what is our real bread and butter is prior discovered resources of other operators where we turn those into very successful developments with our deepwater ability. It is a two-pronged process on Quan. This is a discovery made by Anadarko a few years ago. They were ample Google. That’s a word I just made up things you can look up about Quan flow rates and different operators. We’re just getting our hands on that data just barely getting our hands on it. We believe it should work there, but it will require commercial terms around gas and ultimately leading to power generation in the country.
We won’t be part of that process. It will depend on the gas commercial rate. Obviously, the country here wants us to have a viable field development plan, their words. So for it to be viable, there’ll have to be a price that we can make the type of returns that were needed with all the different aspects we have in our company. So that’s one process well put by you. We have a team working on that, our Kingsey team, our development team under Eric and managing that. And then we have work in the seismic. So the seismic has been shot. There’s 3D seismic owned by the government throughout all the area. It doesn’t have to be shot from scratch. There will be some modernization of that seismic through reprocessing that will be ongoing. And a few months here, we’ll be receiving that data in and have ample time to make our decisions about drilling. We’re really excited to have a look alike to the major field to our east. There’s a very nice prospect in 502. There’s shallow water in 102 that would be similar to what we have in Vietnam, and we’re successful in shallow water Malaysia and many prospects in 709. There’s been oil and different things discovered here. It’s always good to get a new data set and look forward, but really like this because we have a possible development with exploration on the other side in Vietnam, we have exploration with the development. And we’re transposing older to be done Canada today to get into those two opportunities and go forward with our real expertise, which is offshore development. Devin McDermott: Great. Thanks, Roger. Helpful detail. And I wanted to shift over sticking with offshore, but to the Gulf of Mexico. And if we look at your plans here over the next few quarters, you have a series of tiebacks through the back half of this year and early 2024, kind of concluding with St. Malo and Lucius. After that, do you have further tieback opportunities or development opportunities that you’re evaluating now for 2024? And can you kind of put this all together for us as you think about the cadence and outlook for production into next year and investment next year in the Gulf of Mexico? Roger Jenkins: I’m going to have Eric walk you through that, Devin. Eric Hambly: Thanks, Devin. It’s always nice to talk about our plans here in the Gulf of Mexico. We, as you may have noticed, we’ve done a really tremendous job with our King’s Quay development with the Khaleesi-Mormont Samurai fields. We have highlighted on previous calls and discussion that with the performance that we saw from the fields in the first year or so, we were expecting that, that field development would remain on a plateau production of around 30,000 net BOE per day well into 2025. Recently, we’ve been producing those fields closer to 40,000 net BOE per day. If we continue to maintain those type of rates, then the plateau period may shorten up just a bit. So in conjunction with the normal type of development of that field, we’re monitoring the field performance and then evaluating other opportunities for further development. At this time, we’re looking at potentially a number of future wells or zone change workovers in the Khaleesi-Mormont Samurai field that would extend that plateau. We haven’t formed a budget yet for ’24, but we’re evaluating those things and likely to have a well or two in that area show up. As you pointed out, we’re getting onto the Dalmatian DC 90 #1 well here in this quarter, third quarter, and then we’ll have a Marmalard #3 well. As you move into 2024, early, we’ll have some Lucious non-operated wells come online. And then the Sao Malo Waterflood project, the remaining scope there is to complete two previously drilled injectors and install facilities related to water injection and should see water injection by late in 2024, which will support flattening and potentially increasing volumes from St. Malo for years to come, so quite a bit going on there. And as always, we continue to work through our portfolio with excellent subsurface work and by our teams and try to identify any other opportunities we may have in the Gulf of Mexico. And we’re likely to see those continue to have tieback or new well opportunities 1, 2, 3 a year. for the foreseeable future, which is why we have communicated sort of a long-range view of maintaining our offshore oil volumes pretty steady out for the next five or six years. Devin McDermott: Great. Thank you. Roger Jenkins: Thanks Devin, I appreciate the call. Operator: The next question in the queue comes from Leo Mariani with ROTH MKM. Your line is open. Roger Jenkins: Good morning, Leo. Leo Mariani: Hey good morning, everyone. I was hoping to drill down a little bit more on sort of the share buybacks here. I guess that something you guys announced a while back. As you’ve obviously pointed out, you’ve got lower CapEx in the second half of the year and production is higher here. So, you haven’t done anything yet, but it sounds like maybe this is something that we should expect in the near future. I would imagine that the blackout period on that might be over, maybe as soon as tomorrow. So are you guys kind of prepared to start to get after the share buyback here given that we’re kind of a month in the second half of the year?
Roger Jenkins: Yes, we are, Leo. We’re very excited about doing that. And you framed exactly what we’re talking to our Board about just this week, and our formula is working. The Canadian proceeds closing will enhance it and get us back as we’ve said a lot this morning, and I appreciate the call from everyone. It’s really a movement of some older locations forward and into Cote d’Ivoire with the development and into Vietnam with the development plus exploration. We’re very excited about returning to shareholders. We’ve been a major dividend player across our history. We’ve doubled our dividend in the last couple of years. And now, we’re ready to execute share buybacks, as we feel our shares undervalued, and I look forward to doing that throughout the year, and there’ll be open periods. And Tom and his team are working on various ways of executing buybacks. We see it from peers, and we’ll be able to do it too, and we look forward to doing it. And really are setting up. We have strong production this quarter, some of the highest guided oil maybe we’ve had, and I don’t know when, the highest third quarter production forecast we’ve ever had with hurricane season a long time, capital decreasing, capital decreasing significantly, abandonments behind us, contingent payments behind us, and we look forward to a real strong second half of the year of rewarding shareholders at Murphy. Leo Mariani: Okay. That’s helpful. And then, just wanted to turn to the exploration side here. So, I guess you’re bigotspudregial OSO in the near future. I just want to get a sense, if you guys have kind of an estimate of how long they’ll take, once you kind of start redrilling. Is that kind of a couple of months to decision? And looking at 2024 exploration, you did mention two wells in Vietnam, also should be expecting anything else next year on the exploration front, maybe another well in the Gulf. And I think, I’ve heard you guys say in the past that, probably don’t drill anything else in Brazil or Mexico in ’24. So, I just wanted to get a high-level sense of what could be on the docket exploration-wise in the next 18 months here. Roger Jenkins: It’s a two-part answer. I’m going to let Eric handle the drilling his team, he manages the drilling at the company. He’ll talk about the OSO time, and then I’ll talk about the 24 plans. Eric Hambly: Yes. Thanks, very much. On OSO, just to clarify, we’re not redrilling the well. We’re going back to drill the well with some enhanced equipment, a managed pressure drilling system, which will allow us to drill the bottom section of the well, but we’re reusing a lot of the well we’ve already drilled. So, I just want to clarify, it’s not a complete redrill. We’re going to start that work in the third quarter, and we should have complete that activity kind of by the middle of the fourth quarter. Roger Jenkins: Okay. As the rest of our program, yes, we’re looking to drill two wells in Vietnam. We do not have our budget prepared, do not have it approved by our Board. We’re likely to do that. I would imagine, we would drill a couple of wells in the Gulf of Mexico. I’m not sure that are working interest. We have ample opportunities. We have opportunities with some other partners. And so, we’ll probably have a four-well program, a couple of wells in the Gulf, couple in Vietnam, and that will probably do it because, again, we’re trying to honor our framework at the end of the deck, our capital at the end of the deck. We want to, as you just asked, talk get buying back stock and rewarding our shareholders while we’re undervalued, and we’re interested in that, too. So, that’s kind of what we’re thinking about that, Leo. Thank you. Leo Mariani: Okay. That’s helpful. So, it sounds like probably nothing on the docket for Brazil or Mexico in ’24? Roger Jenkins: That’s right. Leo Mariani: Okay. Thank you. Roger Jenkins: Thank you. Operator: The next question in the queue comes from Arun Jayaram with JPMorgan. Please proceed. Arun Jayaram: Hey Roger, I wanted to get some thoughts or details on your technical team and what type of experience does your team have in work in West Africa, Cote d’Ivoire? And maybe just give us some insights on how the exploration team is situated here at Murphy and Houston. Roger Jenkins: Thanks, Arun, for that question. We’ve worked everywhere in the world. We had a year ago business in Gabon. We had a development, a very unique development in Democrat Republic of Congo. All of our executive team have worked internationally. Murphy is an international player. This is a far easier drilling than an OSO well, much shallower, much more simple execution. We’ve executed wells like that throughout the world. We have a technical team on the drilling side. It’s great experienced internationally. And then our development, development is a development. This is around the same water depth as King’s Key this isn’t very anything difficult for us. On the exploration side, naturally, a major company like Anadarko is a very successful exploration company in a great company. There personnel from Anadarko that work in different other offshore entities today, including Murphy. But we have a very experienced team, both through exploration and of course, executive management and our development team that’s very experienced working internationally. Tom, Eric and I have lived and worked and traveled internationally, our entire careers, and this is really just not really much to the execution for us, Arun. We are greatly experienced and able to execute globally on just about anything in the ocean. I can’t think of the thing we can’t do in the ocean.
Arun Jayaram: Great. Roger, one housekeeping question. It’s a good quarter for you guys. We did note that you tweaked your oil growth year-over-year to 8% from 10%. Is that conservatism? I just want to get some thoughts on what drove that variance? Roger Jenkins: Well, I’m not going to be unconservative I have my EVP of operations today here with me only beat guidance by 7,000 a day this quarter when you say conservative. I think what’s going on here, it’s kind of we’re doing extremely well, and our guidance is very strong for hurricane season. We are a very big Gulf of Mexico player. We all know that. I would think of that as a positive. We’ve had some operational matters at Dalmatian throughout the year. We’ve also covered that up with some really incredible performance early in the call, Eric, mentioned our strong plateau rates at King’s Key and Eagle Ford doing extremely well. And so we’ve had some issues there, and we’re going to need to get this well online to help that field produce better, if you will, that’s caused a loss. We put on our onshore wells earlier than planned, and they’re doing extremely well when they come on early and plan you sort of overproduce it then and then they decline toward the end because we’re front-loaded capital company to have more returns for our shareholders with less capital at the end of the year, we’re also being helped by great oil prices today. So that’s what’s going on. We have Terranova basically hardly anything flowing. So it’s hopeful to flow there. We’re doing extremely well this month. Any kind of help on Hurricane season or Dalmatian is a great well that we drilled a year ago. Our team is already executing that well. So I think we can still get back to where we were, but felt that this was the proper guidance today and be sort of a reckoning, if you will, in our production post-hurricane season at our next quarter and the sale of the assets that we’re making today get all that going. We’re doing extremely well today, incredible high rates at this time. I’m super pleased with Eric’s team on that. And I think it’s just a little conservatism to what we have today, but we have ample ability to cover it up and get back to where we were last quarter. I’m quite pleased how we’re headed. Arun Jayaram: Great. Thank you, Roger. Roger Jenkins: Thank you, Ryan. Appreciate it. Operator: The next question in the queue comes from Charles Meade with Johnson Rice. Please proceed. Charles Meade: Good morning, Roger to you and the Murphy team there. Roger Jenkins: Thanks, Charles. Charles Meade: Roger, there’s been a lot of talk about service costs going up in the offshore. And I think that’s more or less at least the talk is that’s happening worldwide. So I wondered if you can talk a bit about whether you’re seeing that or whether you’ve seen that, the degree to which you’ve seen it so far? And what is — how much service cost increases are contemplated in your current forecast either for the back half of 2023 or 2024. And I’m wondering if perhaps that is one of the big contributors or maybe even the main contributor to you raising the low-end of CapEx guidance for the year? Roger Jenkins: Eric is a little closer to that. Charles, I’m going to let him walk you through that. Eric Hambly: Thanks, Charles. Charles, we’re in a pretty good position relative to offshore cost right now. In the first half of this year, we were working a rig in the Gulf of Mexico that was at a rate significantly below market in the $300,000 per day type range. The market is probably in the 450-ish range per day. And we were fortunate enough to lock in rig slots to conduct our planned activity well into 2025 into early 2025. We have locked in rig rates at a little bit below what is kind of current market rate. So you have that going on, which is really helping us not see inflation beyond what we had expected well in 2025. There are some other cost pressures as you can imagine, in the industry casing costs, sometimes they’re moving up and down. We monitor that pretty carefully. That’s a big thing for us. And other related services to executing our program are pretty minor really look at the rig and the casing costs are driving most of the costs. So relative to a lot of people, we’re feeling really good about our positioning on our cost offshore through 2024. Beyond that, we’ll be exposed to market type of rates. So for our planned activities in 2025 at least the last half of 2025, we’ll have to see how the market is looking on rig rates and kind of be exposed like everybody else with in the industry. Charles Meade: Got it. That’s helpful detail. Thank you. And then if we could go back to the – OSO well. Roger, when I look at the, I think, your — main resource for that is 150 MBoe and that actually pretty big these days for a single well in the Gulf of Mexico. Can you talk a little bit about what — about the nature of that target or maybe possibly targets in that well? And how risky you see that your risk of success there? Roger Jenkins: Thanks, Charles. A real good question. Yes, that’s a very large prospect. One of the larger ones being drilled. This is a classic massing play up against salt years ago. Chevron drilled this prospect and never reached the objective to hitting salt prematurely. The seismic has been reprocessed in that area. We feel like we have the prospect now going up against salt with all the major typical massing fields in that area. This has been a bit of an underdrilled area in the Gulf. They’re ample structure here. This is not a lot of infrastructure here as people got back close to platforms to drill, if you will. This is also a very competitive place in the last lease sale. We picked up some leases here under severe competition with Chevron coming in here.
We also have a great partner in our well and Oxy who back in the Gulf, very strong and a very successful private equity company who’s on the lease with us since day one. Very excited about the well. It’s not a simple well to drill. It is also a new seismic data set. OBN type data being shot through this region right on top of the well. That tells you that the industry is greatly interest in the area. The lease sale was greatly interested, and we have a key prospect up in the middle of it. And we’re excited to drill the well. It’s a big well. I wouldn’t — it’s not a low risk well, but it’s the new thing to drill, and we’re happy to have a lease in it. We’re happy to pick up some more in it and we’re happy to see everyone come — get around us there, which means we’re on to the right thing. We have a great partner with Vicki at Oxy, and we like working with them and a great PE partners is very successful. So we’re very excited about the well and getting back to it. Charles Meade: So kind of a classic three-way up against salt with a chance to stack up a few sands? Roger Jenkins: That’s correct. We also have a very nearby prospect called Rushmore that would derisk that, offsetting an area where Chevron bounce and pay years ago, reallocated to other parts of the Gulf. So a good follow-on prospect there, and new leasing in the area, and it could be a new hub in the Gulf BP as a big prospect near here. And we’re excited about the necessary. Charles Meade: Thanks for the detail Roger. Roger Jenkins: Thank you. Appreciate it. Operator: And the next question in the queue comes from Josh Silverstein with UBS. Please proceed. Roger Jenkins: Good morning, Josh. How are you doing? [indiscernible] you there — Josh. Josh Silverstein: Sorry. Yes. So the non-core exit of the Duvernay, a little bit of the Montney wonder a full exit of the Duvernay, it’s not been an area that’s received a lot of capital, a little bit of infrastructure constraints. Why don’t you just look at look to exit the whole area? Thanks. Roger Jenkins: I’ll let Eric go through that. Eric, likes Duvernay. I do too. Eric Hambly: Yes, I do very much like Duvernay. Josh, we did a really nice job with the Duvernay of conducting a program years ago, fully holding and appraising that asset. And the part of the Duvernay that will remain, I have to say we’re really happy with the performance there from the well performance as well as our ability to get our cost structure to be very competitive. So the economics of those locations are quite strong. And the way we think about Duvernay is, we are not in any kind of pressure to head out there and have activity just to have activity. But as we work through our Eagle Ford inventory and we get from the bulk of our Tier 1 locations in Eagle Ford behind us, the Duvernay really competes quite well with the rest of the Tier 2 and 3 type of Eagle Ford opportunities, and we’ll end up shifting our focus or adding focus rather to the Kaybob Duvernay, because the economics of those locations are really strong, and we’ve highlighted previously in our slides in our call that we have a lot of years of 15 years of shale oil locations between the Eagle Ford and Kaybob that breakeven under $40 a barrel. So this is a part of a long runway for us of maintaining our shale oil volumes and scale and diversity in our business. And we think of it as core, and we’re really excited about the potential it has to contribute to our business for decades. Josh Silverstein: That’s helpful and a good segue to the next question, which is the Eagle Ford well performance has been really strong this year. You guys highlighted some of the Tilden wells. How are you guys thinking about capital allocation into the basin? Do you want to try to accelerate some of the activity levels next year because the performance has been pretty strong this year? Thanks. Roger Jenkins: Yes. Josh, that’s a great question. I always like to talk about our great well performance. So thanks for asking that. We’ve highlighted previously that we were pretty excited to try out our new enhanced completion style in Tilden. We have not until the second quarter of 2023, had a Tilden well online since 2019. So as we’ve featured, we’ve done a lot of work on enhancing our completion design in Karnes and Catarina, and we put it to work here this year in Tilden with two four-well pads. That Jambers pad, we have more production performance data from it than Tino, and it’s showing just great performance, so doubling effectively our production rates on an IP30 basis. The other pad, we saw pretty much in line with expectations.
So overall, great results. We still need to do a little work there to figure out how we can make every single Tilden well really great, but we’re really pleased with what we’re seeing. When you think about big picture, Murphy, what we’re trying to do, we don’t really respond reactively to certain results from limited number of wells in one quarter and change our capital allocation. What we’re trying to do with our Eagle Ford business is to maintain it flat in the 30,000 to 35,000 BOE per day net to Murphy range for the near term and use cash flow generated from the asset to follow our framework to delever, execute explorer and return value to shareholders through the form of share repurchases and dividend and debt reduction. And that’s what we’re kind of going to stick to as we work to come up with our 2024 budget, I would imagine a similar type of level of activity in Eagle Ford as we’ve had in the last couple of years. Josh Silverstein: Great. Thank you guys. Roger Jenkins: Appreciate the question. Thank you. Operator: [Operator Instructions] The next question in the queue comes from Roger Read with Wells Fargo. Please proceed. Eric Hambly: Good morning Roger. How you have been? Roger Read: Very good, Eric. I hope everybody is doing well there. At least it was a good quarter. Eric Hambly: Doing well. Yeah, very good. Roger Read: Yes. I’d just like to maybe come back on kind of two things that have been hit. One, in terms of the debt pay down and making sure that you don’t overpay for early retirement. Is it safe to assume that you’ll build cash on the balance sheet in advance and that should be something we would anticipate. And I’m just thinking if commodity prices stay a little higher, we’re able to generate more free cash. Is that the right way to think about things? Roger Jenkins: I’ll let Tom walk you through that, Rogers real close to that. Tom Mireles: Yes, Roger, thanks for that. The way we’re thinking about it is we have this priority to hit our debt targets. And we have these annual targets. So how we execute it quarter — through the quarter will — may vary. But we are going to be focused on reducing that debt. And it will probably be more weighted towards the fourth quarter as we start building up more adjusted free cash flow. But we’ll try to get some done this quarter as well. And as we mentioned earlier, those 25 are trading at par here just in a few more weeks, and we’ll probably focus on taking those out. Between the debt and the share repurchase again, those are annual targets. And so we’ll try to do that as efficiently as possible. So how that weights within the quarter may vary a little bit. But that’s the thing that Roger and I will be focusing on with our Board is to try to do that as efficiently as possible. A – Roger Jenkins: Yes. I want to add on to that, Roger, is what we really try to do is if we can catch some dislocation, like I think some of our peers are doing we’re monitoring the various ways we may do a little bit ahead of the repurchase in some quarter over another and have the year add out perfectly to the formula. And also of note right at the end of the year, the debt target of the 27 notes reduces — I mean the purchasing of price, it’s might be hard to execute that right at end of the year. We’re monitoring all that the math on interest expense to the call price, and Tom’s team is greatly focused on that. But what we’re really excited about to be in a position of lower CapEx number contingent payments, incredible production and higher oil prices those are all good things to solve. That’s a really good meeting to have of how we’re going to spend all our free cash flow, and that’s the meeting we’ve been looking for a year, we’re there today. Roger Read: Okay. Thanks for that. And then I’m trying to think the right way to sum up this question. But — as we think about Murphy as an exploration company, and you mentioned in some areas, maybe a little more competition in trying to get to the right blocks, but there’s also some areas that not in that seem to be super high profile, I think in some parts of West Africa and South America. So as you’re looking at the areas that you’re focused on — do you get the feeling that the opportunities are there and not too competitive given that some others are maybe a little too focused on, like I said, the high-profile things that are going on. I was just wondering if you kind of think about how we progressed maybe over the last several quarters or last couple of years in terms of your opportunity to get the exploration blocks that you want? A – Roger Jenkins: Thanks for your question, Roger. We’re active global explorer in the past, a lot more than we are now. We try to keep it into less countries. We try to work in places where we can primarily work here in Houston. So we have some criteria that we look at. We also like to have places where we can do some possible development work of prior discoveries. We’re not a super major in that regard and interested really in East Coast Canada. Wells are too expensive for us. There are some success offshore Namibia that’s gone for a long time and enormous expense on seismic and wells. That’s not really our focus. We’re very well known globally for our ability to execute and compete, if you will, with super majors occasionally, countries want a different type of a partner.
And we’re actively reviewing that, and we’re really happy about — these are two very large additions we have here with, now with our field development Vietnam, allowing us to execute many opportunities there. We didn’t want to execute our drilling there. So we had our field development plan prove that suddenly came forward that’s changing. Cote d’Ivoire is a very big, large acreage area. We’ve been working on that for a very long time. So — we’re not out in some big global hunt for more exploration acreage. We monitor and know about everything globally. Because again, we’re trying to walk our way through our lower growth, high return back to shareholder business is, again, getting this debt paid down, which is — you just asked Tom about that. And we’re well positioned toward that more than going out and looking at very expensive country entry at this time. Roger Read: All right. Appreciate it Thanks. A – Roger Jenkins: Thank you, Roger. Take care. Operator: We have no further questions in the queue. I’ll turn the call back over to Jenkins. Please proceed. Roger Jenkins: Okay. Thank you. I had a real good call today. Thanks to everyone focusing on the key questions about how we add shareholder value at a very good quarter, anticipating another one coming up and get into our framework and thank everyone for participating today, and see everyone soon. Appreciate it. Thank you. Operator: Ladies and gentlemen, this will conclude your teleconference. Please disconnect your lines.