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

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

As such, no assurances can be given that these events will occur or that the 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.

Roger Jenkins: Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. As we turn to Slide 3, I’d like to reiterate our corporate priorities of deliver, execute, explore and return. We remain firmly on track for achieving our $300 million debt reduction goal in 2024, leading to $1 billion of total long-term bond debt outstanding at the year-end 2024. In the first quarter of 2024, we exceeded production guidance in the Eagle Ford Shale and Tupper Montney with total production of 170,000 barrels equivalent per day at the high end of our guidance range. Murphy’s Gulf of Mexico Workover Program is ongoing. In addition, I’m pleased to report that the Mormont #2 subsea well is back online in the first quarter after equipment repair.

We will continue to progress our well delivery programs and in the second quarter, we will have a new well at Khaleesi and 23 new operated wells all to come online. In exploration, our operating partner is currently drilling the Ocotillo exploration well in the Gulf of Mexico, and we will move to the Orange exploration well immediately following. In the first quarter, Murphy was awarded six deepwater blocks from the Gulf of Mexico Federal Lease Sale 261. We’re also progressing our exploration plans in Vietnam as we’ve contracted a rig to spud our exploration program in the beginning of the third quarter. We’re pleased to continue our hallmark of consistent returns to our shareholders through buybacks and longstanding dividends. We’ve repurchased $50 million of stock in the first quarter at an average price of $39.25 a share.

Additionally, as announced in January, we increased our quarterly dividend to $0.30 per share, our 120, I am sorry, $1.20 per share annualized and our Board maintained this level in April, which is back to a 2016 annual level. Our cap allocation focus has been primarily focused on debt reduction since 2020. Between August 2020 and August 2022, excuse me, we reduced total debt by $730 million. Since announcing the framework in August of 2022, we’ve consistently executed a combination of debt reduction, share repurchases and dividend increases. And since the total year 2020, we’ve reduced debt by $1.7 billion. We purchased a total of $200 million in stock or 4.7 million shares at an average price of $42.68 a share and raised our quarterly dividend 140%.

In the first quarter of 2024 specifically, we generate sufficient adjusted cash flow to allow us to purchase 50 million of stock and capitalize on stock price dislocation prices to oil prices. For 2024, we’re solidly on track to achieve our $300 million debt reduction goal and reach Murphy 3.0 of our capital allocation framework, especially with current oil prices. Looking forward to reaching this next step and further increasing shareholder returns to 50% of adjusted free cash flow later this year. Slide 5, Murphy produced at the high end of guidance at 170,000 barrels equivalent in the first quarter of 2024, with 89,000 barrels of oil per day. We achieved a slight premium to WTI as we realized $78 per barrel and our realized NGL price was $23 a barrel and nat gas was $2.12 per thousand cubic feet.

Overall, we generated $746 million of revenue in the quarter, excluding our non-controlling interest. I’ll now turn the call over to our Executive Vice President and Chief Financial Officer, Tom Mireles, for an update on our financial results. Tom?

Tom Mireles: Thank you, Roger, and good morning, everyone. Slide 5. In the first quarter, Murphy reported $90 million of net income or $0.59 per diluted share and $131 million of adjusted net income or $0.85 per diluted share. We achieved $405 million of adjusted EBITDA due to a combination of strong production and realized prices, with $264 million of accrued CapEx, excluding non-controlling interest. Overall, as Roger mentioned previously, we had an outstanding quarter in returns to shareholders as we repurchased $50 million of stock, paid a higher dividend and increased our cash balance. In total, we returned over 60% of our free cash flow, all while supporting a front-end loaded CapEx plan with approximately 60% of spending in the first half of 2024.

Slide 6, Murphy maintained strong liquidity in the first quarter, with $1.1 billion as of March 31st, including more than $300 million in cash and equivalents. I’m pleased that during the quarter, we received positive outlooks from both Moody’s and Fitch, revised from stable outlooks previously, with the corporate ratings affirmed at Ba2 and BB+. At quarter end, we had $1.3 billion of senior notes outstanding, with a long-dated weighted average maturity of nearly eight years. We remain on track for further debt reduction this year and I look forward to reaching Murphy 3.0, with total debt of $1 billion before year end. Slide 7, at Murphy, we seek to continually minimize our impact on the environment, whether that’s using natural gas rather than diesel to fuel our onshore operations or utilizing recycled water for our well completions.

We also support the communities in which we work, like the City of Uvalde in South Texas or here in Houston. Because of this service, we have been presented with awards, such as the United States President’s Volunteer Service Award from the Houston Food Bank and I look forward to Murphy developing further initiatives to enhance our positive impact. With that, I will turn it over to Eric Hambly, our President and Chief Operating Officer, to discuss our operational updates.

Eric Hambly: Thank you, Tom. Slide 10. Our Eagle Ford Shale wells performed above expectations in the first quarter, achieving total production of 29,000 barrels of oil equivalent per day, with 86% liquids volumes. Our operating partner brought online four Tilden wells during the quarter, while Murphy progressed our 20-well operated drilling program for the year, as planned. We are on track to bring seven operated Catarina wells online in the second quarter, plus an additional four non-operated Tilden wells. Slide 11. In the Tupper Montney, Murphy produced 348 million cubic feet per day and progressed our 2024 well delivery program, with 13 wells that are either now producing or will be online in the near-term. This will complete our plans for the year.

We are excited to announce that Murphy has joined the Rockies LNG Partnership, which may create future LNG opportunities for our Tupper Montney acreage as projects in the area near completion. This partnership is comprised of Western Canadian natural gas producers, driving LNG export optionality and we are eager to be a part of it. Murphy maintains a strong price diversification strategy, mitigating against AECO price exposure. For the first quarter, we sold approximately half of our natural gas volumes at the Chicago, Dawn, Malin, Emerson, Henry Hub and Ventura price points. Slide 12. Our Kaybob Duvernay asset produced 4,000 barrels of oil equivalent per day, with 68% liquids in the first quarter of 2024. We progressed our development program for the year and have three operated wells coming online in the second quarter, as planned.

Slide 13. Our Gulf of Mexico assets produced 73,000 barrels of oil equivalent per day, with 82% oil volumes. This production was impacted by approximately 13,000 barrels of oil equivalent per day of planned downtime events during the quarter. Murphy is advancing our development program for the year and we look forward to bringing online the sizable Khaleesi #4 well in the second quarter, as we found approximately 200 feet of net pay when drilling. We are also progressing the drilling of a new well at our Mormont field, which is scheduled to come online in the third quarter. Additionally, our operating partner has brought online wells at the St. Malo and Lucius fields during the quarter. In Offshore Canada, we produced 6,000 barrels of oil equivalent per day in the first quarter, according to plan.

Slide 14. During the first quarter, we completed the zone changes on the Marmalard #1 and #2 wells, as planned, as well as the subsea equipment repair at Mormont #2. Murphy also initiated work on the Neidermeyer #1 well workover, with the plan now updated to drilling a sidetrack well, which will delay the online date to the third quarter of 2024. Our workover expenses, which are included in our lease operating expenses, total $50 million for the first quarter, with $65 million forecast for the second quarter. This figure includes the cost of the Neidermeyer sidetrack well. Additional work is planned later this year at the Dalmatian #2 well for the subsurface safety valve repair, as well as the non-operated Kodiak #3 well, stimulation and zone addition.

Slide 15. In Vietnam, we have been progressing our plans for our Lac Da Vang Field Development Project, including advancing a ward of major contracts this year. We look forward to begin drilling our development wells in 2025 and remain on schedule for achieving first oil in late 2026. Slide 17. In the Gulf of Mexico, we’re excited to begin our 2024 exploration program. Our operating partner is currently drilling the Ocotillo exploration well. Immediately following this well, the rig will shift to drill the nearby Orange exploration well. These two Miocene prospects are located near existing infrastructure and could be brought online quickly if either is a discovery. Also in the first quarter, we expanded our portfolio and were awarded six deepwater blocks from the Gulf of Mexico Federal Lease Sale 261.

Slide 18. We’re continuing preparations for our Vietnam exploration program later this year and are excited to have contracted a rig which is currently drilling in-country. Murphy will first bud the Hai Su Vang exploration well in Block 15-2/17 in the third quarter and target a mean to upward gross resource potential of 170 million barrels of oil equivalent to 430 million barrels of oil equivalent. The rig will then move to drill the Lac Da Hong exploration well in Block 15-1/05, targeting a mean to upward gross resource potential of 65 million barrels of oil equivalent to 135 million barrels of oil equivalent. We 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 Côte d’Ivoire and we are pleased at the multiple opportunities available across exploration play types. Importantly, ENI recently announced positive results from its Murene1 exploration well on the Calao discovery nearby. Murphy is excited at this news and I note that our Blocks CI-502 in particular is very near this discovery. In general, our Côte d’Ivoire acreage position is now bookended by two significant ENI discoveries. We will continue to progress our analysis of the data as it comes in, with the final seismic data due by year-end 2024. And with that, I will turn it back to Roger.

Roger Jenkins: Thank you, Eric. On Slide 21, for second quarter 2024, we forecast total production of 176,000 equivalents per day to 184,000 equivalents per day, with 93,000 barrels of oil during that period. This range is impacted by 2,000 barrels of oil equivalent per day of offshore non-op unplanned maintenance primarily related to a third-party downstream facility, 1,250 barrels equivalent per day of Eagle Ford Shale downtime as we have offset frac impacts and a significant downtime of 11,700 barrels equivalent per day at Tupper Montney for plant maintenance that’s ongoing. Murphy plans to spend approximately $325 million of accrued CapEx in the second quarter. The full year 2024, we’re maintaining a production guidance of 180,000 equivalents per day to 188,000 equivalents per day, with 52% or 95,000 barrels a day of oil.

This guidance is supported by stronger own-well performance and better results at non-operated offshore fields. We’re also maintaining our CapEx range at $920 million to $1.02 billion, excluding NCI. These ranges will support us achieving our 2024 debt reduction goal of $300 million, thereby allowing us to reach Murphy 3.0 and enhance our shareholder returns. On Slide 22, effective at year end, our long-term strategy remains unchanged since we first disclosed the refreshed projections following last year’s opportunities captured in Vietnam and Côte d’Ivoire to support our new opportunities and long-term oil production growth. We’ll continue to support and grow our returns to shareholders during this time. In particular, we’ll be executing Murphy 3.0 of our framework after reaching our debt reduction goal this year.

Longer term, we plan to reinvest approximately 45% of operating cash flow, enabling us to achieve average production of approximately 210,000 equivalents per day to 220,000 equivalents per day, and as always, over 50% oil weighting. Murphy will continue generating ample free cash flow to allocate towards further shareholder returns, accretive investment, as well as supporting exploration success. Additionally, as part of this plan, we remain committed to achieving metrics that are consistent with investment-grade rating. And I’m pleased that the rating agency outlook improvements achieved this spring that Tom just spoke of. On Slide 23, I’m glad to have a solid first quarter behind us as we continue to execute our plans for the remainder of the year.

Our long history of consistently returning to shareholders will expand as we reach Murphy 3.0 later this year. We’re already ahead of the game with share repurchase in the first quarter. I view our 2024 debt reduction goal as a given. I look forward to buying back more stock to enhance shareholder value. Additionally, we have exploration upside with drilling two wells in the Gulf of Mexico and two wells in Vietnam. Our future is bright, especially considering our long runway of Gulf of Mexico projects, as well as significant future locations across our North American Onshore business and our exploration upside. As we approach annual meeting season, we often benchmark our peer group on 2023 10-K data. When doing so, we find that Murphy is rated one or two in many categories, a few of those.

Free cash flow per production, the per debt adjusted share growth, production per debt adjusted share growth, lowest reinvestment rates, debt reduction, total debt, debt due 2024 to 2026, debt to EBITDA, total cash return for shareholder change year-over-year, and lastly, G&A for EBITDAX. Solid company, solid plan, diverse portfolio, exploration upside, locations sustainable, the long history of shareholder returns. That’s Murphy Oil Corporation. As always, I want to thank our outstanding employees for their consistent effort and determination to help us reach all of our goals. With that, that’s the end of our prepared remarks today and we look forward to our questions.

Operator: [Operator Instructions] Your first question comes from the line of Neal Dingmann from Truist Securities. Your line is open.

Neal Dingmann: Good morning…

Roger Jenkins: Neal, good morning.

Neal Dingmann: Good morning, Tom. Good morning, Roger. My first question just on shareholder return, you just sort of hit on this, Roger, but I just want to go over. Specifically, could you or Tom remind me what bonds, if any, you were able to repay early and then more — I guess, more importantly, once you get under that billion or to Murphy 3.0, besides just stepping up the shareholder return, could we see more expiration work or what else can we see, because obviously your debt at that time will be well under control. So I’m just wondering, besides stepping up the shareholder return, is there something else we would see with that incremental free cash flow?

Roger Jenkins: Thank you for that question, Neal. It’s a big key part of our strategy. I’m going to give you a big high-level picture and let Tom talk about the specific bonds. We need to think about this framework as a yearly matter. We easily can forecast, as you and all of your peers are, that we’ll easily get rid of this $300 million of debt. There’s nuances to calling the debt at different opportunities. We also have an internal target in our plans of how much stock we can buy. Nobody wants to buy back stock more than me and we see the debt as a given. So we’re already ahead of the game on the stock. We have an eyeball as to how much stock we want to buy and I would see that going along if the debt goes into the third quarter, that’s still something we’ll be able to do as we go along the way, if you follow me on that.

So our strategy is, as far as long-term, we want to keep our plans, we keep our low growth plans, we do not see changes to that plan at any time that I just reiterated and we want to continue to buy back this stock while it’s undervalued. And as you know, by yourself and many of your peers, we’ll be ranked number one in cash flow through 2026 available to our market cap and that’s going to make us have a really big advantage and we’re not really into changing that right now. So I’ll let Tom talk about the specific notes.

Tom Mireles: All right. Thanks, Roger. Yeah, Neal, we got a little over $300 million to go to reach Murphy 3.0 and we’ve got more plenty available in our 2027 notes. Those are callable today and the balance is around $440 million of 2027 notes. And then our 2028 notes will be callable in July of this year. Now, you asked about once we get to Murphy 3.0 and we go into this 50% to shareholders, 50% to the balance sheet. The way we kind of think about that is Murphy 2.0 was about more of a defensive move, making sure we got our balance sheet in a robust shape. Murphy 3.0 gives us a chance to be positioned for more of an offensive move, whether it’s dry powder or more opportunities to return to shareholders, either through buybacks or even dividends.

Neal Dingmann: Thanks, Tom. And then that completely answers it. And just secondly, Roger, maybe a high level on valuation. Just continue, it’s hard not to notice that you all trade below some other companies that have materially less production, I just wanted your opinion. Do you think the market is just still not appreciating the stable offshore production of you all? I look at your inventory. I look at the production, especially not just the onshore, but the offshore development activity and continue to be sort of surprised just the discount. I just would love to hear your opinion on why this discount that I can’t piece together?

Roger Jenkins: Thanks for that question, Neal. Really love that question. This is my 12th year doing this. It used to make me real upset about those matters. But today, we’re just looking to buy back stock. And we’re going to buy back stock until we do better. We have our balance sheet in order to do so. I just rattled off in a long list of positives about our company is solid. Can’t have those attributes about running a good, solid company. I believe it must be the market cap of our company would be similar to all shale and all shale doesn’t have a workover. All shale is a perfectly organized drilling game plan. If we were all shale, I could tell you exactly the production by quarter. It’s almost better to have the same products every quarter.

But if you look at the free cash flow and uniqueness of our company and the deals that we’ve done and the M&A and all the opportunities we have, it’s because we’re in the oil business, we’re in different aspects of the business and we now have ourselves in a situation where growth has slowed, buying back stock is in vogue, we’re going to have the best balance sheet and buying stock, and be patient and get into doing that, especially in 2025, and then we’ll go with the valuation from there.

Neal Dingmann: Makes sense. Well said. Thank you, Roger.

Operator: Your next question comes from the line of Leo Mariani from ROTH MKM. Your line is open.

Leo Mariani: I wanted to touch base on the Gulf of Mexico production here real quick. I heard some of these numbers right. I think you guys said you had 13,000 barrels a day equivalence of downtime in the first quarter. 2,000 equivalence of downtime in the second quarter. So I guess that’s a plus 11,000 barrel a day improvement in 2Q. But just looking at guidance, looks like you’re guiding up around 4,000 barrels a day. So just wanted to get a sense of the delta. Is that just kind of natural declines there in the Gulf?

Roger Jenkins: I’ll let Eric handle that for you, Leo, and thank you for that question.

Eric Hambly: Yeah. Leo, thanks very much. We have quite a bit going on with our Gulf of Mexico program this year. We’ve noted that we have a number of high rate wells that are not currently producing. In particular, the Neidermeyer well that we’re doing a workover, which has now become a sidetrack. That’s a high rate well, about 4,000 barrels a day. Those should come online early in the third quarter. And then in the middle of the year, we have work going on at our non-op Kodiak and our operated Dalmatian to increase production there. So if you think about those just wells that have historically been producers for us, that are coming online toward the middle of the year, you’ll see a ramp. Along with that, we have our Khaleesi-Mormont program that’ll add volumes that will help offset declines.

So as you march through the year, Gulf of Mexico production will increase. And production in Gulf of Mexico in the first quarter was around 73,000 barrels a day and ought to be up 9,000 barrels a day, 10,000 barrels a day, 11,000 barrels a day by the end of the year — at the end of the last quarter, ought to be something like that increase. So offsetting decline with new production and restoring wells to production that have been offline temporarily.

Leo Mariani: Okay. That was very helpful in terms of the explanation. And wanted to also have just kind of a similar line of questioning around the Eagle Ford. Looks like that production ticks down a little bit in the second quarter. You guys cited some maintenance that’s ongoing, but could you maybe just kind of discuss how the Eagle Ford production trajectory should play out as we roll into 3Q and 4Q?

Eric Hambly: Yeah. As you noted, we do have a little bit of downtime in the second quarter. That’s primarily offset frac impact because we have an active completion program going in the second quarter. That program continues into the third quarter. The bulk of our operated wells, which generate most of the new production in Eagle Ford, come online in the third quarter. So you ought to see production peak in Eagle Ford in the third quarter and be relatively similar in the fourth quarter.

Leo Mariani: Okay.

Eric Hambly: For the full year, we’re predicting a 30,000 barrels a day for the Eagle Ford.

Leo Mariani: Okay. That’s helpful. I appreciate it. Thanks.

Roger Jenkins: Thank you, Leo. Appreciate it.

Operator: Your next question comes from the line of Tim Rezvan from KeyBanc Capital Markets. Your line is open.

Tim Rezvan: Good morning, folks. Thank you for…

Roger Jenkins: Tim, good morning.

Tim Rezvan: Hi, Roger. Thanks for taking my question. I was hoping to dig in a little more and follow up on the last question on the Gulf of Mexico. The Neidermeyer, obviously prolific well, 4,000 a day. You said the workover activity became a sidetrack. I was wondering if you could give a little more context on what changed and if you expect that back at full capacity in early 3Q.

Roger Jenkins: Eric will handle that for you. It’s just oil field there, Tim, this morning.

Eric Hambly: Yeah. So what happened with that well is, the workover that we had planned when we got on the well, we expected that the problem was a packer that was leaking. We confirmed in the early stages of our workover that that was indeed the problem. As we progressed with the work to pull the packer and tubing, we were trying to isolate the lower completion from the upper completion. So basically the productive connection with the reservoir from the tubular goods in the top part of the well and we were having difficulty isolating the lower completion and decided that the best path forward to have the best success going forward with that well was instead of continue on that path of continuing to fight to get isolation of the lower completion, that we would sidetrack the well, which would give us an opportunity to have a completely new completed well with a very short offset from the existing location.

We have sidetracked that well. We like what we’ve seen so far. We’re going to move forward with a completion that should be a brand new fresh completion, which has the best mechanical outcome and should provide the best production rate opportunity. So it should produce in line or better than the well that we’re leaving behind.

Tim Rezvan: Okay.

Roger Jenkins: And one note on that, Tim. One note on that, Tim. It’s 4,000 net. These wells — all these wells we have make 16,000 barrels a day to 18,000 barrels a day gross. These are big wells. We have been on 30% something of this one. So it makes way more than four a day.

Tim Rezvan: Sure. Yeah. I get that. Okay. That’s all I had. Thank you.

Roger Jenkins: Thank you, Tim.

Operator: [Operator Instructions] Your next question comes from the line of Charles Meade from Johnson Rice. Your line is open.

Roger Jenkins: Good morning, Charles.

Charles Meade: Good morning, Roger, to you and the rest of the Murphy team there. My first question is on 2Q CapEx. The $325 million guide is called $60 million higher than what I was looking for and I think what some other people were looking for. It looks like what you’ve already laid out that the big driver of that is really the U.S. Onshore completion pace, drilling completion, or I guess I should say North America Onshore Drilling Completion pace. But also that, there’s a lot of work going on in the Gulf of Mexico. Are those the two big pieces or are there other drivers that are contributing to that what looks like high CapEx at 2Q?

Roger Jenkins: Thanks for that question, Charles. I’m going to just frame a little bit and let Eric get into the details. So we’ve said all along that we’re 60% of our CapEx in the first year and we’re still within a percent of that. This is timing of various matters. Timing, actually, we’ve drilled faster and completing faster in the onshore business and we have non-up matters timing on the other. And I’ll let Eric get into the detail after that. So we feel that we’re still in line. Everything’s in line for our debt. Everything’s in line for buyback stock. We just moved a few percent of the CapEx to the left. That’s really no more than that. Eric could give you a detail of that.

Eric Hambly: Yeah. Thanks, Roger. As you noted, most of the change is driven by the timing of our Onshore North America Drilling Completion program. That’s over $30 million of the change. So that’s shifting from later in the year into the second quarter. And then offshore, about $15 million of equipment, subsea equipment related to our Khaleesi-Mormont program. We moved some spending that we expected in the fourth quarter up into the second quarter as we pivoted during the time we had our Mormont #2 subsea equipment issue. And then some seismic spend moved from the first quarter of the second quarter. You know that we had lower CapEx than our original guide in the first quarter. So some of the spending we thought would happen for non-D&C related activities, including seismic and our Lac Da Vang development spending, moved from the first quarter of 2024 into the second quarter of 2024 and that’s another $11 million or so.

So that describes most of the changes in the movement of CapEx really, as Roger pointed out, where just phasing of spending and not overall spending is changing.

Charles Meade: Got it. That is helpful detail. And then, Eric, I want to go back to a comment that you made about this. It seemed like you were pretty positive on this Khaleesi #2 development well, I think it is. And I think you, believe it or not, you mentioned that there are over 200-feet of pay. And I wonder if you could give us two aspects of context and anything else you want to add. And first, how does that 200-feet or whatever you saw in this most recent well, how does that compare to the initial well there? And then the second piece is, is that all in one zone or is that across a few different zones and so we’re going to have a, I guess, what I’m getting at, is this going to be a monster one zone completion or is this the more typical, you have 60-feet in three different zones kind of thing?

Eric Hambly: Yeah. Thanks for that. I appreciate the opportunity to talk about it. This particular well, the Khaleesi 4 well, was targeting a reservoir that was not in our initial development of the field. As we developed the field, we identified some additional opportunities. This particular one is targeting a shallower reservoir in an up-dip position and we — so we penetrated this reservoir as we were going to deeper zones, which were the target of our main field development. This is sort of an additional set of volumes that we were able to develop after the initial development program and we’re excited about it. It is in one zone. It’s a very nice looking reservoir with high reservoir quality. Should produce very well for us here as it comes online soon.

So if you think about our overall Khaleesi-Mormont-Samurai development, we had an initial set of wells, which we’ve talked about how they’ll do production-wise. In the development, we have Khaleesi and the two Mormont wells that we’re doing this year are similar. They’re targeting zones that were not contemplated in initial development. They’re additional volumes, which will allow us to extend the plateau of our total Khaleesi-Mormont-Samurai development. So from that perspective, we’re really excited. This development’s been tremendous for us with very fast payout, already happened. And additional volumes going forward with plateau production out into 2025, 2026.

Charles Meade: Okay. That’s great detail. Thank you.

Eric Hambly: Thanks.

Roger Jenkins: Thanks, Charles. Appreciate it.

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

Roger Jenkins: Appreciate everyone dialing in today. Had some good dialogue there with our business. We’re very, very pleased with our business, looking forward to the rest of the year and beyond. Appreciate all the attendance today and we’ll be seeing you soon. Check in with our IR team if you have any further questions. Thank you all.

Operator: This concludes today’s conference call. You may now disconnect.