Good morning, everyone, and thank you for joining us on our First Quarter Earnings Call today. Joining us is Roger Jenkins, President and Chief Executive Officer; along with David Looney, Executive Vice President and Chief Financial Officer; and Tom Mireles, Senior Vice President, Technical Services. Eric Hambly, our Executive Vice President of Operations is currently attending a Harvard University executive program. In the interim, Molly Smith, Vice President, Drilling and Completions has temporarily assumed his responsibilities. 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 and financial amounts are adjusted to exclude non-controlling interest in the Gulf of Mexico. Slide 1, please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. As such, no assurance 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 2021 Annual Report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statement. I will now turn the call over to Roger Jenkins.

Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. Turning to Slide 2, Murphy continues to deliver a strong value proposition. Our ongoing execution excellence from our three producing areas proves that we are a long-term sustainable company. Our competitive advantage is continually reinforced, most recently with the achievement of first oil ahead of schedule from the Khaleesi, Mormont, Samurai and King’s Quay floating production system in April. We continue to generate strong cash flow with higher oil prices realized this year, we’ve been able to increase our shareholder returns through quarterly dividend raises as well as accelerate our debt reduction goals. Lastly, our meaningful level of board and management ownership highlights our personal interests in the company’s long-term success. Slide 3, Murphy remains focused on three strategic priorities of delever, execute and explore. Since the start of 2022, we’ve increased our debt reduction goal. Now targeting $600 million to $650 million for this year with first step to achieve through the redemption announcement on Monday of this week of $200 million. Overall, we believe this goal is achievable at an $85 per barrel WTI price and current production guidance for the year. Longer-term, we have forecasts having the optionality of up to an additional $1 billion of debt reduction in 2023, assuming only $75 per barrel pricing. We continue to review our overall debt target for additional accelerated reductions. Additionally, our delevering efforts are being recognized by external credit agencies, as Murphy’s recently upgraded to Ba2 by Moody’s and received a positive outlook from S&P. As we announced in early April, we reached a significant milestone of first oil from the King’s Quay floating production system; the two wells from the Khaleesi, Mormont, Samurai field project are currently flowing with field uptime far exceeding our expectations. Completions are ongoing with five wells remaining, though we anticipate the next well to flow imminently. I’m pleased that our onshore wells are progressing slightly ahead of schedule. And for quarter two, we have 11 of 23 operated wells already flowing in Eagle Ford Shale with 10 operated wells in the Tupper Montney coming online as well. In Eagle Ford Shale, the team has been enhancing our completion methods in real-time, leading to early indications of high production levels in the first wells online this quarter. Our third priority is exploration. We’ve been granted an additional exploration period in Block 5 offshore Mexico by the regulator, and we are advancing plans to drill the Tulum exploration well later this year. We’re also working with partners on our 2023 exploration program, which we anticipate to include two operated wells in the Gulf of Mexico. On Slide 4, for the first quarter of 2022, Murphy produced an average of 141,000 barrels of equivalent per day with 60% liquids content. This is at the high end of our guidance range due to outperformance from our oil-weighted assets. We recognize strong oil pricing in the quarter with more than $95 per barrel for oil and $42 per barrel for NGL, leading to a total revenue of $764 million. Overall, I’m pleased to see that our realized prices are back ahead of the WTI benchmark for this quarter. I’ll now turn the call over for a financial update from our Chief Financial Officer, David Looney.

Thank you, Roger, and good morning, everyone. Slide 5, for the first quarter, we reported a net loss of $113 million or $0.73 net loss per diluted share. Certain after-tax item adjustments included a $149 million non-cash mark-to-market loss on derivatives and a $77 million non-cash mark-to-market loss on contingent consideration. As a result, we reported adjusted net income of $113 million or $0.73 adjusted net income per diluted share. Cash from operations for the quarter totaled $338 million, including the non-controlling interest and also including an $81 million reduction due to working capital changes. After accounting for net property editions and dry hole costs of $245 million, we achieved positive adjusted cash flow of $93 million. In the first quarter, we reported a crude CapEx of $301 million, and we also made $55 million in total contingent payments related to our two Gulf of Mexico acquisitions closed in 2018 and 2019. Slide 6, as just mentioned, our total accrued CapEx of $301 million in the quarter was above our original $270 million guidance for a few specific reasons. Most significantly were unavoidable inflation impacts for fracking services and oil country tubular goods. We also made the decision to adjust the scope of our work in the Eagle Ford Shale to account for higher completions intensity, which is already paying off and in the Tupper Montney to drill longer laterals. The remaining CapEx impact during the quarter was the result of additional rigs standby costs for non-operated exploration drilling in Brazil. For the full year 2022, we’ve raised the midpoint of our CapEx guidance by 7% establishing a new range of $900 million to $950 million. Beyond the impacts I just mentioned, we also have a scope impact from the Samurai field in the Gulf of Mexico due to further evaluation of additional pay zones and completions. Overall, we’re maintaining our previous production guidance of 164,000 to 172,000 barrels of oil equivalent per day with 53% oil and 58% liquids weighting. With ongoing high oil prices, we continue to forecast a high level of excess cash flow for the year, which we intend to direct towards $600 million to $650 million of debt reduction, in addition to reviewing our dividend quarterly with an ultimate target of returning to historical payout levels. Slide 7, our cash position remains strong. And as of March 31, cash and equivalents totaled $481 million. As we’ve often stated, our company is focused on delivering. With ongoing strong operational and financial execution, we achieved the first steps in 2021 and announced new targets for this year in January with prices much higher than forecast in the first quarter and first production now achieved from the Khaleesi, Mormont, Samurai project. We’re in a great position to reach our debt reduction targets with the first redemption of $200 million announced earlier this week, which will be executed in June. With that, I’ll turn it back over to Roger.

Thank you, David. Slide 8, Murphy’s been increasingly focused on operating sustainably. Our drilling and completion team has replaced over 1 million gallons of diesel fuel with natural gas and has improved water recycling, using an average of 20% of total frac volumes utilizing recycled water in the first quarter of 2022, while also reducing the industry’s footprint by recycling offset operators' water as well. Meanwhile, operations at Kaybob Duvernay have achieved a 20% reduction in emissions for 2022. Lastly, I’m pleased to state that Murphy has been designated a best place for working parents in 2022 by the Greater Houston Partnership. Turning now to operational updates on Slide 10. Murphy produced 30,000 barrels equivalent per day in the Eagle Ford Shale for the quarter with 85% liquids, just over 1,000 barrels a day equivalent above our plan. Nine gross non-operating wells were brought online with five wells in Karnes and four wells in the Tilden area. Our well deliveries remain on schedule for the year. Murphy’s completions team has done an outstanding job this year and through reviewing real-time completion data has enhanced completion intensity in our wells. The first 11 wells began producing early in the second quarter, and we are very pleased with the initial results. The company has sought ways to capitalize on higher oil prices and launched a workover campaign in Eagle Ford Shale in the first quarter, targeting wells that could achieve less than a six-month payout with measurable impact on OpEx. To date, we have selected 60 of these well opportunities. Slide 11 in the Tupper Montney, Murphy produced 242 million cubic feet a day for the quarter. We’re advancing our well cadence on schedule with 10 wells planned to come online in the second quarter rather. The team evaluated our existing well permits and adjusted development plans to drill longer laterals, leading to enhanced well recoveries and slightly higher costs. Additionally, while we’ve seen a significant rise in AECO price in this quarter, we estimate a royalty impact of 1,100 barrels of oil equivalent per day for the full year 2022, assuming a C$4.82 AECO price for the year. This AECO price is assumed in our current production guidance, estimating our royalty rate for the year to be approximately 6%, which is far below any other North American unconventional play. The Kaybob Duvernay on Slide 12, Murphy produced 7,000 barrels of oil equivalent per day in Kaybob Duvernay with 70% liquids content as three wells came online during the quarter, producing just above our oil volume type curves. These are solid wells producing an IP30 of 800 barrels per day. And these completions allow us to retain a key acreage area for our company. This is our last work for the year in this play. On Slide 14 in the Gulf of Mexico, our assets there produce 59,000 barrels equivalent per day for the quarter with 80% oil. Overall, approximately 80% of our 2022 capital plan is designated for advancing our major projects, with the remainder spent on development and tieback wells and activity scheduled later this year. The non-operated St. Malo Waterflood Project is also ongoing. On Slide 15, as announced in early April, we achieved first oil at the Murphy-operated King’s Quay floating production system ahead of schedule and on budget. We’ve seen great results so far with the two wells produced and combined growth of 30,000 barrels equivalent of oil per day at approximately 89% oil and the FPSO achieving significant 97% uptime, which is simply unheard of. The third well is anticipated to flow imminently, while completions continue on the remaining four wells in the seven-well project, averaging 40 to 45 days per well. In drilling Samurai four last year, we encountered additional pay zones above the main targets for the field, as well as in the planned targets. This year, our plan includes a sidetrack of the prior drilled Samurai three well to primarily evaluate these zones further. This well was very successful and found nearly 140 feet of pay above our main objectives in the field. As a result, we’ve increased our capital for additional evaluation of this well and completions in the planned development zone. Turning to exploration on Slide 17, the third point of our strategic priorities is to explore. In the first quarter, Murphy received regulatory approval for an additional exploration period in Block 5 in Mexico. We’re progressing the necessary permits and approvals ahead of drilling the Tulum well later this year as the operator. Earlier this year, we participated in an exploration well in Brazil, which found no hydrocarbons. The operator plugged and abandoned the well, and the partner group is evaluating the results; Murphy has expensed the well. Looking ahead, we’re advancing our plans to drill two operated wells in the Gulf in 2023. In Slide 19, as David mentioned previously, we are revising our CapEx midpoint 0.7% higher with a range of $900 million to $950 million for the year, approximately 65% of the spending is forecasted to occur in the first half of the year, while 80% of the Gulf of Mexico CapEx is earmarked for our major projects. Second quarter 2022 production is forecast at 156,000 to 164,000 barrels equivalent per day, at 60% liquids. This production range was reduced by operated planned downtime of approximately 5,500 barrels equivalent per day, primarily onshore and non-operated offshore downtime of 3,400 barrels equivalent per day. As well as continuing to come online from the Khaleesi, Mormont, Samurai project, along with our onshore well execution plans, we project an average of a 10% increase in total production each quarter with the first quarter production significantly higher than 2021. We maintain our full year 2022 production guidance of 164,000 to 172,000 barrels of equivalent per day, comprised of 53% liquids and 58% liquids. On Slide 20, Murphy remains focused on this long-term strategy through 2024, we continue to accelerate our delevering goals at higher oil prices, including optionality for $900 million to $1 billion of net reduction in 2023, at conservative prices to today’s strip. We forecast delivering average production of 188,000 barrels equivalent per day at a CAGR of 7% with an average of 52% oil weighting through 2024. Additionally, offshore production is maintained in this period at 80,000 barrels equivalent per day. The exploration program remains another focal point of the company with a portfolio of approximately 1 billion barrels of oil equivalent net risk potential resources. Overall, our plan has provided excess cash flow that we will direct toward enhancing our payouts to shareholders, while accomplishing our debt reduction goals and dividend increases simultaneously. As you look longer term 2025 to 2028, our plan remains intact as we forecast our current portfolio produces an average annual volume of 195,000 barrels per day equivalent, which approximately 50% oil weighting, while we target a corporate investment grade rating. During this period, we forecast generating ample cash flow, which will be used for additional cash returns for shareholders through dividends and buybacks and accretive investments. On Slide 21, looking forward in 2022, our three-pillar strategy remains unchanged and we continue to advance our debt reduction goals; execution continues to be a significant focus as we work through completing the remaining wells at Khaleesi, Mormont, Samurai, as well as our onshore plans and bringing production on without issues. The production resulting cash flow generated from these wells further supports our ongoing shareholder returns through quarterly dividends. Furthermore, while execution time is important, a key point of our execution strategy is to maintain top-tier safety and environmental metrics and send everyone home safely at the end of the day. Lastly, we continue to target our exploration program, I look forward to the opportunity in offshore Mexico as we drill later this year. In closing, I’d like to extend my deepest thanks to our CFO, David Looney, for his service to the company over the past few years. David relieved me when I was seriously ill with COVID in March of 2020 to lead our company in some of the most difficult times ever in our industry. I and our Board of Directors thank Murphy – thank David for that, and I wish he and his wife, Beth, all the best in their retirement. I’ll now turn the call over to the operator and be glad to take any questions you might have. Thank you.

Thank you. We will now begin the question-and-answer session. Your first question comes from Arun Jayaram with JPMorgan. Please go ahead.

Yes. Good morning. Arun Jayaram from JPMorgan. Roger, David, I wanted to get some thoughts from you around priorities for uses of free cash flow. I know debt reduction is clearly a priority. But when we run our model over the next two years 2022, 2023, we get over $2.5 billion of free cash flow pre-dividend. So I was wondering if you could go through some of the potential buckets, including cash return, there’s obviously the Petrobras asset packages, which is on the block today. And maybe go through what the priorities would be. And then David, in terms of your comments on restoring the dividend to pre-COVID levels, we note that your dividend was $0.25 per quarter during 2016 to 2020 and $0.35 per share in the 2014 to 2016 level. So wondering if you could give us a little bit more refinement on thoughts on where the dividends would go to.

Thank you for that question, Arun, about our longstanding dividend; we've been paying the dividend since 1961. And we’re not new to capital returns, as you may know, we’ve paid out over $3 billion to shareholders since 2013 through dividends and buybacks. Our first step is for a once-in-a-lifetime opportunity to greatly delever our balance sheet. And by greatly delevering, we mean paying our debt down to just the IG notes that we have long-term. With current pricing, and I’m sure you’re using that in the JPMorgan model, that can easily be accomplished next year. Because we’re doing well in our execution and because we’re doing really well in following those plans, we’re going to be able to do that while simultaneously increasing our dividend. Until that level of delevering is reached, we will be looking forward, and it’s complicated to continue to advise about dividend increases. But clearly, we’ve done that two quarters in a row and want to continue to do that. The way I simply look at it is, is in 2021, Arun, about 5% to 7% of our free cash flow was paid toward dividend. This year for that to be the same while delevering, our dividend will need to increase on an annual basis. Our last quarterly increase was to $0.175 a share that will be annualized on a $0.70 per year annualized basis, as you know. And that will need to increase in order to just keep up with what we did last year. So our first goal is to keep up where we were last year in 2021, as a percent of that free cash flow, and you can model and calculate that. And then continue on this rapid once-in-a-lifetime ability to delever down to IG, and we’ll be doing those things simultaneously. At that time, we’ll evaluate much larger dividends and hopefully plan for consistent buybacks when we reach that. And your last question involving Petrobras, naturally, we are fully aware of that process. We have a very valuable preferential right in that process, Arun, as you know. And any quality company would be using that and reviewing that as we see fit. We’ve been very good at M&A, I must say, and have accomplished great things doing that. And we would not want to alter that plan and we’ll be reviewing that. And if we share a lot about our views of that, it would hurt our ability to accurately pursue the preferential right, and I’m sure you can understand that.

Yes, fair enough. Okay. Roger, I wanted to get one update from you on the Tupper Montney; as largely anticipated, you did tweak down your volume expectations just on higher royalties given the move in commodity prices. But I was wondering if you could give us an update on where the industry stands in BC regarding the permit situation and any potential impacts to your plan this year or as you think about future capital allocation to the Tupper.

Thanks, Arun, that question about the Montney. We do have a significant resource there. And I must say that the two wells that we’re flowing this quarter are some of the highest rate wells we’ve ever seen and probably some of the best two wells ever in the Montney overall anywhere. So it’s a really good asset for us, naturally. We’re very experienced in Canada having been in Canada for over 60 years; we’re in close contact with the BC oil and gas ministry there, speaking to them on a regular basis. We believe toward the second half of the year there will be some progress going forward on how to achieve more approvals. I’d like to give a shout-out to my team. Because of our vast array of permits, we go by unchanged this year and were able to execute the 20 wells that we had planned, albeit we moved a pad around or two, which required the wells to be drilled longer to be more effective. And that caused a slight increase in capital. So we’re still okay for this year, anticipate improvements going forward toward the second half of the year, around the time of our capital budgeting. And we still believe we’ll be able to execute our long-term plans in the Montney today.

Thanks, Roger, and David, best of luck in your future endeavors. There’s a lot of golf and fishing in your future production.

Thanks, Arun. I appreciate it. Thanks. Thanks, Arun, talk to you soon.

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

Thank you, good morning.

Good morning, Paul.

Good morning, Roger and David. And David first best wishes and hope you have a lot of fun in your retirement doing a lot of golfing.

Thanks, Paul.

That – maybe this is for David. You say the inflation factor on the 2022 project. Any idea that – how that is going to seep into 2023 and 2024 compared to your payments. I think previously you’ve been looking for maybe about 650 for say 600 to 650 for 2023. And maybe a new deal for 500, or maybe an under 500 for 2024. And given the environment that we see, how that is going to be changing and also for the contingency payment, can you remind us what is the remaining liability or the terms for the next several years? That’s the first question.

Thanks; a lot of questions, Paul. I’m glad. Dave’s going to have to retire after that.

Yes, exactly. Thank you. Thank you, Paul. Those were both very good questions. I’ll address the inflation question first. Very good point. You’re correct. Obviously, we’ve been saying for a while that our average CapEx for 2022, 2023 and 2024, the $650 million, certainly based on the increased guidance we provided today for 2022. And then, if you look at 2023 and 2024 in a similar fashion to what we’ve seen this year where the real inflationary impacts we’ve seen have had to deal with our onshore drilling and completion issues. We think that the inflation going into 2023, 2024, I mean, obviously our plan had some small amount built into it. So we – if we tweaked that a little bit higher, I’d just give you a number basically to say that that three-year average for 2022, 2023, 2024 is probably up about $40 million or 5% or something like that. So not a huge increase when you look at spreading that over the three-year period. So on the contingent payments, great question again, both the deals we did in 2018 and 2019 did have contingent payment kickers in them if you will. We look at that from the standpoint of saying it really worked out well for us because we did not have to pay cash upfront on those deals, but we put in for the most part they were revenue triggers so that if revenues exceeded a certain amount in any given year, we would make a payment whereby we would split the additional revenue 50-50 with the sellers of the properties. For example, if you look at the deals and I would point out that we do have a lot of good information in our 10-Ks about the contingent payments. But basically, the payment this year, $55 million was the first time we’ve had to pay on either of these transactions, and the contingent payment structure obviously was put in place when we negotiated the deals in 2018 and 2019. Certainly, it’s a factor of the high prices that we’ve seen towards end of 2021 carrying into this year. I would tell you that, at today’s oil prices and production levels, we would fully expect to make the final payment under the Petrobras deal in March of next year, 2023. That’s the way the deals are structured. You calculate the revenues on an annual basis, and you make the revenue-adjusted payments in March of the following year. So we would expect the Petrobras deal would have an additional payment in March of next year could be in the range of $95 million to $100 million that would max it out under the original agreement we had. Similarly, if you look at the LLOG transaction, again, at current prices and production levels, we would probably be looking at another $90 million payment or so in the first quarter of next year to the LLOG folks, that again would actually extinguish all of the obligation with respect to that transaction, because the 2022 fiscal year is the final year of calculation under that particular structure. So regardless of what happens in 2023, there’ll be no additional payments related to the LLOG deal that it would be finalized based on 2022 production. And again, that is at current pricing levels that we’re looking at today and current production forecast that we have for those specific properties. And then if you roll all that together again, we would expect those two obligations to be extinguished effectively with those payments in March of 2023. There is a first oil payment that we agreed to make related to the King’s Quay facility or Khaleesi, Mormont, Samurai field. One of those payments, which was $25 million was made in April; that’ll show up in the second quarter, and there would be another similar payment a year from just April likewise to that $25 million. So that’s the entirety of all the contingent payments. Hope that answers your question.

Paul, I’d like to add a little further color to that. When we did these deals, we’re quite proud of these contingent payments. We didn’t pay forward upfront. These were revenue curves set at the time of the deal in which when that party receives that contingent payment, we have the other piece of it. So we’re sharing above the revenue line in both of these deals, 50-50 with the other party. We did not know oil would go up at that time. We’re glad to make the payments because we’re getting a piece of it, and we’ve done very well in the M&A by contingent payments, but $100 oil that came on the route, and we’re glad it did because we’re making a lot of money on these projects, and we didn’t pay it upfront two years ago. So that’s the way the deals are structured. It turned in favorably for the other party, but we share in that reward as well, Paul.

Okay, great. Just a final question real quick, what is the first quarter weather impact production curtailment in Eagle Ford if that’s any.

In the first quarter of this year?

Yes.

We had none.

None. Okay. Thank you.

Our de minimis level, Paul. Thank you, Paul.

Your next question comes from Neal Dingmann with Truist Securities. Please go ahead.

I’ll try to keep my under four or five questions. Maybe Dave makes feel good for you. And just a quick one for you. Just – could you talk a little bit on cash taxes, obviously? Nice to see on just the cash flow profit continuing to go up. Maybe just comment on what you expect to see on that.

Yes, Neal. Thanks for the question. Very, very good. Obviously, with our NOL out there in excess of $2.5 billion, it does shield a lot. We should perhaps be paying a small amount of cash taxes this year at the current level we’re talking about. But then really we would – we’re expecting now to, if you will, burn through the NOL around 2024, as long as oil prices stay above $90 on average. So the current things that we’re paying generally have to do with Canada, and they’re pretty de minimis amounts from a cash tax perspective. But as you look out into the future at today’s prices, we’re probably good towards the end of 2024.

Okay. David, regarding pricing, it seems like we have discontinued. Could you discuss what anticipated pricing may look like in the next few quarters?

Neal, Dave is catching his breath. Let me do dip. Paul wore him down. Hang on, let me get to my notes in this matter. I think the best way to talk about our company from a differential perspective is that if you look at our total crude oil for the year, let’s say 85,000 to 87,000 barrels a day. 35% is Mars. 21% is HLS, which is a Heavy Louisiana Sweet, and 27% is MEH, which would be Eagle Ford Shale. Of course, we have East Coast Canada with that, and we have very strong print pricing there along with our cascade Chinook FPSO in the Gulf. So HLS for the year, we’re forecasting probably a $1.20 to $1.50 positive for MEH about the same. And we originally had Mars at a $2 negative dip for the year. So with 48% of our Gulf Coast barrels being non-Mars and 35 at Mars, we can overcome that easily. As a matter of fact, we had great realized results in the first quarter. And back when we were really rolling, we were ahead of WTI, because we have a very strong realized basis with our Gulf Coast barrels. Now recently, while we had forecasted a negative dip to Mars with the SPR coming in cheaper to refineries than the Gulf of Mexico crew was shipped exported. This of course did no good to the SPR, as you would anticipate. And therefore, now with Euro barrels off the market, this has gone up to where there’s hardly any negatives if at all in the current market. So while we have a negative $2 for the year, we’re very pleased about as the word we see today in the EU about reductions of Euros further. And that being that replacement with the drip in slow of the SPR, we can end up positive across the board here on our Gulf Coast barrels. And we’re very pleased about it.

Okay. That looks really like a nice setup. I'm glad to hear that. And then lastly, you remiss, I didn’t ask just on King’s Quay a bit, Roger, it really sounds like you’re running a bit ahead of schedule. So, not only maybe just verifying that you’re more than satisfied with it. What is – is there capacity after all these initial wells come on? Can you talk about it? Is there additional capacity beyond that? Maybe just give us perspective as far as how it’s looking now and what is even the future upside there?

Thank you, Neal, so much for that. Great question. It’s a big project for us. I just cannot tell you how well my teams have done, and not just the execution, the installation, but the pre-commissioning and the collaboration with our production teams, achieving 97% uptime, probably 10% to 15% better than industry in a new start facility. It’s an incredible result. And the wells are doing extremely well. We have one well extremely powerful out there, doing extremely well. This is a nameplate, border plate deal of 80,000 barrels a day. We should be able to fill that. We hope, of course, when you get into the facility and sell facilities running, there are some debottlenecking things that can be done. I know our team is looking at that, and with this additional pay that we found at Samurai in the future, we’ll be very happy to fill it up and look for some 10,000 barrel a day debottlenecking there. And but we still have to get all the wells on, but we’re very pleased to find more pay at Samurai. I can tell you that’s a great deal for us because it’s inside infrastructure; it’s a lay-down tieback if it’s inside the field, as you can anticipate great uptime, and great results, great team, and we’re very fortunate to have them.

No, I’m looking for all the upside there. Thank you, Roger.

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

Good morning, team, and thanks for all the updates this morning. The first question was around exploration. Obviously, we got the update out of Brazil, but just Roger, if you could talk about the exploration portfolio as you see from here, what are you excited about? And as it relates to Brazil, how we should be put that in the context of the broader company?

Thank you for the question. It’s an important one as it's one of our main priorities. Regarding Brazil, we are indeed disappointed with the recent results. However, we remain very optimistic about the overall prospects. The Block and the Cutthroat well had promising, high-quality reservoirs, but unfortunately, they didn’t yield hydrocarbons. We need to focus on this and recognize that there are still multiple high-impact exploration opportunities available that are not affected by this outcome and are being developed at different depths. We have a substantial acreage position in Brazil, amounting to 1.6 million acres, which presents many opportunities that are disconnected from the Cutthroat well specifically. When we look at exploration as a whole, we aim to maintain a risk portfolio that aligns with our proven reserves. Currently, we are slightly advanced in that regard. In the exploration business, while trying to be strategic with capital, ensuring steady oil production with modest growth while simultaneously enhancing our dividend leaves little room for extensive exploration spending. Over the past two years, we've been involved in two significant exploration wells alongside leading U.S. supermajors, Chevron and Exxon Mobil. While we are proud of this collaboration, the outcomes did not meet expectations. Moving forward, we will be focusing on smaller prospects that we will operate ourselves, which allows us to leverage our operational efficiency. Our strength lies in timely execution, particularly in offshore projects. We anticipate drilling several promising wells in the Gulf next year, including the Cascade/Chinook East well, which we have been developing since acquiring the property through our venture. We also have another well planned in the Central Gulf of Mexico that we’re optimistic about, along with our operated well in Mexico this year. These represent attractive sub-salt opportunities akin to those we have historically encountered in the Gulf. We are positioned just outside of recent successful projects in Mexico, and there is additional activity from operators like Shell nearby, which makes this an exciting time. We are moving into a phase where we will have control over the regulatory processes, permitting, capital expenditures, and operations, enabling us to maximize the value that Murphy can deliver.

Thanks, Roger. And the follow-up question is, we did see the positive actions taken by Moody’s here. Can you just talk about the progression towards investment grade and conversations you’re having with ratings agencies as we would argue moving to investment grade would help to improve the cost of capital of the business.

Thanks, Neil. David, it’s caught his breath, and he is going to relieve me on that matter now.

Thank you. Yes, it’s a great question, Neil. Obviously, we’re always in regular contact with all three of the rating agencies, and needless to say, they’re very pleased with what we’re doing from the perspective of debt reduction, et cetera. Obviously, strengthening the balance sheet, all those kinds of things, we think we’re moving in a great direction, and of course, we have no ultimate control over what they do and when they do it. But I think the feeling we’re getting, if you will, is that we continue our deleveraging program. As Roger had talked about earlier with the increased production coming on from Khaleesi, Mormont, Samurai, seeing that particular project coming online, that’s meaningful to the agencies as well. So I think the combination of all those things really just puts us in a really good spot from the perspective of being well-positioned to potentially get upgrades into the investment grade area.

Thank you, guys.

Thank you.

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

Good morning, Roger.

Good morning, Charles.

Yes, good morning. And David, congratulations on your retirement. I hope our paths cross again somewhere.

Likewise, Charles, thank you.

Yes, Roger, I want to ask you a little bit more about what you saw in this Samurai development well. It’s not clear for me, you reading the release, whether it was just more pay in the upper zone or it sounded like it was a new zone. And I’m imagining that, that if this was just some 10-foot stringer or something like that, that you guys saw, you wouldn’t be mentioning it. So can you give us a sense of, I recognize this earlier, but can you give us a sense of – what the relative magnitude may be? And it sounds like this could be maybe its own subsea development somewhere down the line. And is this kind of a known field pay or are there – is there offset production from the zone?

Thanks for that question, Charles. Great. We tried to be a little clear now release actually found really nice pay in this well to 140 feet above the zones, which we were working. So let me just take a few minutes to walk you through. Very pleased with this whole development, how this is going last year; there were two development wells in Samurai with two deeper zones. We drill the well last year in a segment of Samurai that hadn’t been explored before and we found additional pay in the main objective area. So we found three zones instead of two in the lower part of the well. Also, on top of that, with some amplitude and some formation and mapping that we had, we were exploring at that time for an upper area of pay, seeing another fields in the region. We were very successful in finding very nice pay in that well. So in our budget this year, and in our CapEx, we plan to sidetrack a previously drilled Samurai three-well to explore for both of those things; the deeper objectives and the upper objectives that was found in the prior well. We did that this year and found a planned pay in the lower part of the well, not excessive or anything like that, but again, very pleased in the upper part of the well. This is also in a cheaper area of drilling and more shallow than the deeper zone of the well and found very nice high-quality sands of 140 feet. So then that will likely add one to two wells on top of this development and probably get the overall field size in Murphy’s view in the 80 million plus range. And we had sanctioned that for a 60 million barrel field. So we’re very excited about it. It’s like finding a 20 million barrel field on top of what you have with infrastructure laying on top of you and really nice pay zones. Very excited about it, and a great job by our subsurface team to identify this, put the capital in, and get it approved to drill that sidetrack this year. We’re very pleased about it, and it’s a very, very big deal for us.

That’s helpful additional color. Thank you, Roger.

Your next question comes from Roger Read with Wells Fargo. Please go ahead.

Good morning.

Good morning.

How are you all doing? I have questions regarding both the balance sheet and cash flow. Earlier, Roger, you mentioned the dividend and the plan to restore it. I'm curious if you or the Board considers it from a yield perspective, the payout ratio, or the payout in relation to production, and what might be a base-level commodity price for that discussion? Additionally, could you share what benefits Murphy might gain from achieving the IG rating, apart from the obvious reduction in debt costs? Are there any other operational or financial factors we should consider?

Thanks for that question, Roger. Great question. To our dividend, I mean, we’re – like I said earlier in prior questions, very proud of our dividend history. Naturally, you anticipate getting it back to where it was. It was $1 before COVID and was cut to $0.50; today, on an annualized basis, we’re at $0.70. Years ago in the prior uptime of all, it was $1.40. If this type of level of prices remain and the way our company with our cost structure and the way we’re executing, we would now be moving beyond the pre-COVID level and beyond; I’d be looking to do that rapidly through quarterly group, of course, we have to get that approved from our Board. Our thought of our Board is to continue to increase to where we were before COVID back in 2012, 2013, 2014 timeframe, we were paying $1.40 and beyond and with consistent buybacks, once we get this once-in-a-lifetime delevering down. So, our focus is to get to IG notes simultaneously pay this year similar to 2021, which would require additional dividend increases throughout the year, going into next year, the same position again, and continue on that march, get the dividends in very, very good shape, and then see where we are in our company around the consistent buyback program. And that’s where we’re headed. In more of that, in lieu of the yield is when you’re a big dividend payer and you want to be a dividend payer and want to get back to that, that means more to than a specific yield and stopping. And then we see a lot of value creation. And two things for us, Roger. One is equitizing our EV. If we keep our multiple where it is, and we continue to pay down debt, the equity portion of our EV will go up, and then we continue to improve our dividend status and then trying to get to a consistent buyback status. We think we’ll be in a very, very well-positioned with the assets we have, how we’re performing, how we’re executing, and doing that long-term.

Yes, Roger, great question. Glad you brought it up. As Roger here just referenced, Murphy has always been a very, very strong balance sheet-oriented company, et cetera, for years; we were investment grade before things happened in the 2015, 2016 timeframe, et cetera. But a return to investment grade is very important to us for some of the obvious reasons as you referenced whether it be renegotiating a bank facility ahead of the 2023 maturity; obviously helps if we’re in an investment grade position there, as well as just overall cost of capital you referenced. And then I think the other thing I would highlight as well is, as you know, Murphy has always been a globally oriented company, and some of the projects that we get involved in, whether they be local or whether they be international, the counterparties and government entities, et cetera, are always looking for someone with strong financial backing. Obviously, that investment-grade rating means a lot when we get into those situations from the perspective of bonding issues, et cetera, et cetera. So it’s just a has multiple add-on effects for us given the way that we run our business and given the way our business lays out really across the globe.

That’s great. Thanks, guys.

Thank you.

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

Good morning. Good morning, Leo. Good morning. I was hoping you all could talk a little bit about what you think the peak rate is going to be on those seven wells that are attached to the King’s Quay facility here on a net basis to Murphy. So as we get towards the end of the year, where do you think this thing peaks out net to Murphy?

I think originally our plans are, Leo, thank you for that question about our great project there. Our net going in early is around 23,000 to 24,000 barrels a day. We think the wells can make, let's say, 4,000 net time seven, is 28,000 is kind of where we are today. We have different ownership in the Samurai where we’re 50/50, we’re on 34% of the facility of the Khaleesi, Mormont fields. And of course, we do have a specific 18.75% royalty in the Gulf of Mexico. That’s kind of where we think that’s headed. And we’re in early days with just two of the five wells on, but we are very pleased with where we are today.

Okay. So it definitely sounds like trending a little bit above expectations, certainly at this point.

Yes. I would agree with that for sure.

Okay. And then can you provide a little bit more color on the Eagle Ford, you all obviously have chosen some kind of more intense completions. It sounds like these wells maybe just came online, here recently the first of 11, I think you cited, but does it look like these things are trending a little bit above some of the earlier time curves? Is it a little too early to tell?

I’ll have Molly handle that question for you, Leo. She’s on top of that matter.

Thanks, Leo. That’s a great question. I’m glad you asked that. I’d like to address our onshore. As you mentioned, we do have these 11 wells turn online are earlier, and they are performing above type curves. So we are very excited about this result. We still have six more turn online making 23 Eagle Ford for this quarter. And we, in addition, we also are turning on more lines in Catarina in Eagle Ford Shale. We have six more coming online in Q1. And we even have going to third quarter more wells coming online Eagle Ford Shale as well. So it’s been very – it is very early, but we’re very excited about the wells coming online earlier and at higher results.

Okay. Thank you.

Okay. We have no more callers in our queue. Today, it’s been a long call here today. We appreciate everyone listening in, and we’ll be back next quarter. And thanks everyone for their attendance today and appreciate it. Any questions, just get with our IR team, and they’ll be glad to help you out. Thank you so much. Appreciate it.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines. Have a great day.