Murphy Oil Corporation (NYSE: MUR) Q1 2022 earnings call dated May. 04, 2022
Corporate Participants:
Kelly L. Whitley — Vice President, Investor Relations and Communications
Roger W. Jenkins — President and Chief Executive Officer
David R. Looney — Executive Vice President and Chief Financial Officer
Analysts:
Arun Jayaram — JPMorgan — Analyst
Paul Cheng — Scotiabank — Analyst
Neal Dingmann — Truist Securities — Analyst
Neil Mehta — Goldman Sachs — Analyst
Charles Meade — Johnson Rice — Analyst
Roger Read — Wells Fargo — Analyst
Leo Mariani — KeyBanc — Analyst
Molly Smith — General Manager
Presentation:
Operator
Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corp. First Quarter 2022 Earnings Conference Call. [Operator Instructions]
I would now like to turn the conference call over to Ms. Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.
Kelly L. Whitley — Vice President, Investor Relations and Communications
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 noncontrolling interest in the Gulf of Mexico. slide one. 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 statements.
I will now turn the call over to Roger Jenkins.
Roger W. Jenkins — President and Chief Executive Officer
Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. Turning to slide two. 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 interest in the company’s long-term success. slide three. Murphy remains focused on three strategic priorities of delever, execute and explore. Since the start of ’22, we’ve increased our debt reduction goal now targeting $600 million to $650 million for this year with first step achieved 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 forecast 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 has recently upgraded to Ba2 by Moody’s and received a positive outlook from SandP. As we announced in early April, we reached a significant milestone of first oil, the King’s Quay floating production system with two wells from the Khaleesi, Mormont, Samurai field project 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 2, we have 11 of 23 operated wells already flowing in the Eagle Ford Shale with 10 operated wells in the Tupper Montney coming online as well. In the Eagle Ford Shale, the team has been enhancing our completion methods real time, leading to early indications of higher production levels and the first wells online this quarter. Our third priority is exploration.
We’ve been granted an additional exploration period in the Block five offshore Mexico, by the regulator, and we’re advancing plans to drill the Tulum exploration well later this year. We’re also working with partners on our 23 exploration program which we anticipate to include two operated wells in the Gulf of Mexico. On slide four. For the first quarter of ’22, Murphy produced an average of 141,000 barrels equivalent per day with 60% liquids [conduct]. This is the high end of our guidance range due to outperformance from our oil-weighted assets. We recognized strong oil pricing in the quarter with more than $95 per barrel for oil and $42 per barrel of NGL leading to a total revenue of $764 million. Overall, I’m pleased to see that our realized prices are back ahead of WTI benchmark for this quarter.
I’ll now turn the call over for a financial update from our Chief Financial Officer, David Looney.
David R. Looney — Executive Vice President and Chief Financial Officer
Thank you, Roger, and good morning, everyone. slide five. 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 noncash mark-to-market loss on derivatives and a $77 million noncash 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 noncontrolling interest and also including an $81 million reduction due to working capital changes. After accounting for net property additions and dry hole costs of $245 million, we achieved positive adjusted cash flow of $93 million. In the first quarter, we reported accrued capex of $301 million. Also, we made $55 million in total contingent payments related to our two Gulf of Mexico acquisitions closed in 2018 and 2019. slide six.
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 rig standby costs for nonoperated 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 seven. 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 delevering, 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 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.
Roger W. Jenkins — President and Chief Executive Officer
Thank you, David. On slide eight, Murphy has been increasingly focused on operating sustainably. Our drilling and completion team has replaced over one million gallons of diesel fuel with natural gas and has improved water recycling, an average of 20% of total frac volumes utilizing recycled water in the first quarter of 2022, while also reducing industry’s footprint by recycling offset operators’ water as well. Meanwhile, operations at Kaybob Duvernay have achieved 20% reduction in emissions for ’22. 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 ten. Murphy produced 30,000 barrels equivalents per day in the Eagle Ford Shale for the quarter with 85% liquids, just over 1,000 barrels a day equivalent above our plan. Nongross — nine gross nonoperated wells are brought online with five wells in Karnes and four wells in Tilden area. Our well deliveries remain on schedule for the year. Murphy’s completions team has done an outstanding job this year in through reviewing real-time completion data as enhanced completions 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 the Eagle Ford Shale in the first quarter, targeting wells that could achieve less than 6-month payout with negligible impact on opex. To date, we have selected 60 of these well opportunities. slide eleven. 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 this quarter in the second quarter, rather. The team evaluated our existing oil permits and adjusted development plans to drill longer laterals, leading to enhanced well recoveries and slightly higher costs. Additionally, while we’ve seen significant rise in AECO pricing this quarter, we estimate a royalty impact of 1,100 barrels of oil equivalent per day for full year ’22, assuming a C$4.82 AECO price for the year. This AECO price is assumed in our current production guidance, and we estimate 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 twelve. Murphy produced 7,000 barrels of oil equivalent per day in the Kaybob Duvernay with 70% liquids content as plans, 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 produced 59,000 barrels equivalent per day for the quarter with 80% oil. Overall, approximately 80% of our 2022 capital plan is designating for advancing our major projects, with the remainder spending on development and tieback wells and activity scheduled later this year. The nonoperated St. Malo waterflood project is also ongoing. On slide 15. As announced in early April, we’ll achieve 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 producing a combined gross 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 7-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 include a sidetrack of the prior drill 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 to explore. In the first quarter, Murphy received regulatory approval on an additional exploration period in Block five in Mexico. We’re progressing the necessary permits and approvals ahead of drilling in Tulum well later this year as the operator. Earlier this year, we participated in exploration well in Brazil, which found no hydrocarbons. The operators plugged and [banned] 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. On slide 19, as David mentioned previously, we’re revising our capex midpoint 7% higher with a range of $900 million to $950 million for the year. Approximately 65% of the spending is forecast 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 wells continue to come online, from Khaleesi, Mormont, Samurai project along with our onshore well execution plans, we project an average of 10% increase in total production each quarter, with the fourth 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, oil rather and 58% liquids. On slide 20. Murphy remains focused on its 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 delevering average — delivering rather average production of 188,000 barrels equivalent per day at a CAGR of 7% with an average 52% oil-weighting through 2024. Additionally, offshore production is maintained in this period at 80,000 barrels equivalent per day. Exploration program remains another focal point of the company with a portfolio of approximately one billion barrels of oil equivalent net risk potential resources.
Overall, our plan is to provide excess cash flow that we will direct towards enhancing our payouts to shareholders while accomplishing our debt reduction goals and dividend increases simultaneously. As you look longer term, ’25 to ’28, our plan remains intact as we forecast our current portfolio produces an average annual volume of 195,000 barrels per day equivalent, with 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 to shareholders through dividends and buybacks and accretive investments. On slide 21. Looking forward in 2022, our 3-pillar strategy remain unchanged. 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 plants and bring production on without issues. The production and resulting cash flow generated from these wells then further support to our ongoing shareholder returns through quarterly dividends.
Furthermore, while execution timing 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 this later this year. In closing, I’d like to extend my deepest thanks to our Chief Financial Officer, David Looney, for his service to the company over the past few years. David relieved me when I was very ill with COVID in March of 2020. He led our company in some of the most difficult times ever in our industry, and 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 will now turn the call over to our operator and be glad to take any questions you might have. Thank you.
Questions and Answers:
Operator
[Operator Instructions] Your first question comes from Arun Jayaram with JPMorgan. Please go ahead.
Arun Jayaram — JPMorgan — Analyst
Yes, good morning. Arun Jayaram from JPMorgan. Roger and 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. And so I was wondering if you could go through some of the potential buckets, including cash return. There’s obviously the Petrobras asset package, which is on the block today. 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 dividend could get to.
Roger W. Jenkins — President and Chief Executive Officer
Thank you for that question, Arun, about our long-standing dividend. I’ve been paying a 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 alone. 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 [adjust] 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 and 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, in 2021, Arun, about 5% to 7% of our free cash flow was paid toward dividends. 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. And 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’re going to be doing those things simultaneously and 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 in MandA, 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 actively pursue the preferential right. And I’m sure you can understand that.
Arun Jayaram — JPMorgan — Analyst
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 BSEE regarding the permit situation and any potential impacts to your plan this year, or as you think about future capital allocation to the Tupper.
Roger W. Jenkins — President and Chief Executive Officer
Thanks, Arun, for 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 over 60 years being in Canada. We’re in close contact with the BSEE, Oil and Gas ministry there, speaking to them on a regular basis. We believe toward the second half of the year will be some progress going forward of how to achieve more approvals. I’d like to give my hats off to my team because of our vast array of permits, we go by unchanged this year and able to execute the 20 wells that we had planned, albeit we moved a pad around or 2, 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. We anticipate improvements our way forward toward the second half of the year around the time of our capital budgeting, and we still believe we will be able to execute our long-term plans in the Montney today.
Arun Jayaram — JPMorgan — Analyst
And David, best of luck in your future endeavors. Hope there’s a lot of golf and fishing in your future. Talk soon.
David R. Looney — Executive Vice President and Chief Financial Officer
Thanks, Arun. Appreciate it.
Operator
Your next question comes from Paul Cheng with Scotiabank. Please go ahead.
Paul Cheng — Scotiabank — Analyst
And David, first, best wishes and hope you have a lot of fun in your retirement, doing a lot of golfing.
David R. Looney — Executive Vice President and Chief Financial Officer
Thanks, Paul.
Paul Cheng — Scotiabank — Analyst
Maybe this is for David. You cited the inflation factor on the 2022 budget. Any idea that how that is going to spill over into ’23 and ’24 comparing to your payments? I think previously, you’ve been looking for maybe about $600 million to $650 million for 2023 and maybe a new-built for $500 million or a new-built under $500 million 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.
Roger W. Jenkins — President and Chief Executive Officer
That’s a lot of questions, Paul. I’m glad Dave is going to have to retire after that.
David R. Looney — Executive Vice President and Chief Financial Officer
Yes, exactly. Thank you, Paul. Those are both very good questions. I’ll address the the inflation question first. Very good point. You’re correct. Obviously, we’ve been saying for a while that our average capex for ’22, ’23 and ’24 is $650 million, certainly based on the increased guidance we provided today for 2022. And then if you look at ’23 and ’24 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 ’23, ’24, I mean, obviously, our plan had some small amount built into it. So if we tweak that a little bit higher. I’ll just give you a number basically to say that, that 3-year average for ’22, ’23, ’24 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 3-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. So 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 the 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 happened in 2023, there will be no additional payments related to the LLOG deal but 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 ’23. There is a first oil payment that we agreed to make related to the King’s Quay facility or the Khaleesi, Mormont, Samurai field. One of those payments, which was $25 million was made in April, it will show up in the second quarter, and there would be another similar payment a year from this April, likewise to that $25 million. So that’s the entirety of all the contingent payments, I hope that answers your question.
Roger W. Jenkins — President and Chief Executive Officer
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 for it upfront. And these are 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 Mmoan allA by contingent payments. But at $100 oil that came on to roost 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.
Paul Cheng — Scotiabank — Analyst
Okay. Great. Just a final question. What is the first quarter [weather] impact production curtailment in Eagle Ford, if there’s any?
Roger W. Jenkins — President and Chief Executive Officer
In the first quarter of this year?
Paul Cheng — Scotiabank — Analyst
Yes.
Roger W. Jenkins — President and Chief Executive Officer
We had none or de minimus level, Paul.
Operator
Your next question comes from Neal Dingmann with Truist Securities. Please go ahead.
Neal Dingmann — Truist Securities — Analyst
I’ll try to keep my under four or five questions. Maybe, Dave makes feel good for you, got 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.
David R. Looney — Executive Vice President and Chief Financial Officer
Yes, Neal, thanks for the question. Very, very good. Obviously, with our NOL out there in excess of $2.5 billion, it does yield 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.
Neal Dingmann — Truist Securities — Analyst
Okay. And then, David, just on price, it looks like [Indecipherable]. Could you just talk a little bit about — I know the SPR is on the Mars barrels. Could you just talk about what kind of expected pricing we might see in the next couple of quarters here?
Roger W. Jenkins — President and Chief Executive Officer
Neal, Dave has got to catch his breath. Let me do the dip [Indecipherable]. Paul wore him down. Let me get to my notes in just a 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 suite, and 27% is MEH, which would be Eagle Ford Shale. Of course, we have East Coast Canada with that, and we have very strong [brent] pricing there along with our Cascade Chinook FPSO in the Gulf. So HLS for the year, we’re forecasting probably $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 [Indecipherable], 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 SPRs you would anticipate. And therefore, now with Euro barrels off the market, this has gone up to where there’s hardly any negative, if at all, in current market. So while we have 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.
Neal Dingmann — Truist Securities — Analyst
Okay. No, that’s why I look — really looks like a nice setup. I’m glad to hear that. And then lastly, be 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 I mean not only maybe just verify that you’re more than satisfied with it. What is — is there capacity after all these initial wells come on? Can you just talk about it? Is there additional capacity beyond that? Maybe just give us a perspective as far as how it’s looking now and what is even the future upside there.
Roger W. Jenkins — President and Chief Executive Officer
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 with the pre-commissioning and the collaboration with our production teams. 97% uptime, probably 10% to 15% better than industry and a new start facility. It’s an incredible, incredible result. And the wells are doing extremely well. We have one well is 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 feel that. We hope, of course, when you get into the facility and sell the 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. But we’ll be very happy to fill it up and look for some 10,000 barrel a day debottlenecking there. And — but we still got 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 laydown tieback if it’s inside the field, as you can anticipate. Great uptime, great results, great team and very fortunate to have them.
Neal Dingmann — Truist Securities — Analyst
No, I’m looking forward all the upside there. Thank you.
Operator
Your next question comes from Neil Mehta with Goldman Sachs. Please go ahead.
Neil Mehta — Goldman Sachs — Analyst
Good morning everyone. Thanks for all the updates this morning. The first question was around exploration. Obviously, we’ve 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 would we put that in the context of the broader company?
Roger W. Jenkins — President and Chief Executive Officer
Thank you for that question. Very good question because it’s one of our key priorities. First, let me just address in Brazil. Of course, we’re disappointed with that result. We remain very enthusiastic about the overall prospects in that block. The Cutthroat well encountered very thick, high-quality reservoirs. They didn’t find hydrocarbons. So now we have to ascertain that and we have multiple high-impact exploration opportunities remaining there that are not related to that, that are sourced in a different way or a different depth horizon and have a long way to go in this play. It’s a very large acreage position with 1.6 million acres there with ample opportunities that aren’t exactly tied to that well at all. So that’s the Brazil question. I think from an overall perspective on exploration, we like to drive with a risk portfolio that’s similar to [our proven]. We’re a little ahead of that now. That’s the first step. When you’re in the exploration business and you’re trying to be very specific with your capital, maintain your oil production with a slight CAGR, delever once-a-lifetime opportunity on your balance sheet while simultaneously increasing your dividend, you really do not have money left over for extensive exploration capital. So in the big scheme of things, when you are involved in several wells, things can go and come in different ways. Over the last two years, we’ve been in two of the biggest exploration wells in the world with two of the most successful U.S. super majors in both Chevron and Exxon Mobil. We’re very proud to be working with them, but the prospects didn’t work. We’re now moving into a period, we’ll be drilling smaller prospects operated by us. And when we operate by us, we’ll have the great advantage of our execution and our real calling card is on time, early, fastest in the industry, high sub-time offshore execution. And we’re moving into a phase of being an operator, which we greatly enjoy. We control the permitting. We won’t have permitting problems because we never have. We control the operation where we do very well, and we look forward to drilling a couple of nice wells in the Gulf next year that we’ll be working and working with partners on. One is a Cascade Chinook East well that we’ve been working on since we bought this property through the MP GOM joint venture and another one well in Central Gulf of Mexico, they’re very excited about. And of course, we have our operated well in Mexico this year. These are laid down subsalt opportunities, very similar to what historically we saw in the Gulf. We’re outboard of success in Mexico. North of us is another well planned by shale in that basin. And we’ve seen other people enter that and have success around us. So those are three nice opportunities, we’re moving into a stage that we control. We control the regulatory, we control the permitting. We control the capex, we control the operational ability to really make value with what Murphy does best.
Neil Mehta — Goldman Sachs — Analyst
And the follow-up is we did see the positive actions taken by Moody’s here, can you just talk about the progression towards investment grade and the conversations you’re having with the ratings’ agencies as we would argue moving to investment grade would help to improve the cost of capital of the business?
Roger W. Jenkins — President and Chief Executive Officer
Thanks, Neil. David has caught his breath, and he’s going to relieve me on that matter. Thank you.
David R. Looney — Executive Vice President and Chief Financial Officer
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, etc., obviously, strengthening the balance sheet, all those kind 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 does just put us in a really good spot from the perspective of being well-positioned to potentially get upgrades into the investment-grade area.
Neil Mehta — Goldman Sachs — Analyst
Thank you.
Operator
Your next question comes from Charles Meade with Johnson Rice. Please go ahead.
Charles Meade — Johnson Rice — Analyst
Good morning. David, congratulations on your retirement. I hope our paths cross again somewhere.
David R. Looney — Executive Vice President and Chief Financial Officer
Likewise, Charles. Thank you.
Charles Meade — Johnson Rice — Analyst
Roger, the — I want to ask you a little bit more about what you saw in the Samurai development well. It’s not clear for me, really the release, whether it’s just more pay in the Upper Zone? Or it sounded like it was a new zone. And I’m imagining 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 — and I recognized 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 is this the — is there offset production from the zone?
Roger W. Jenkins — President and Chief Executive Officer
Thanks for that question, Charles. Great. We tried to be a little clear in our release. I actually found a really nice pay in this well to 140 feet above the zones which we’re working. So let me just take a few minutes to walk you through. Very pleased with this whole development and how this is going. Last year, there’s two development wells in Samurai with two deeper zones. We drilled a well last year in a segment of Samurai that hadn’t been explored before, and we found additional pay in the main objective areas. 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 have, we were exploring at that time for an upper area of pay seen in other 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 to plan and 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 of the deeper zone of the well and found very nice high-quality sands, 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 on a 60-million-barrel field. So we’re very excited about it. It’s like finding a 20-million-barrel field on top of you 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, and we’re very pleased about it. And it’s a very big deal for us.
Charles Meade — Johnson Rice — Analyst
Thank you Roger.
Operator
Your next question comes from Roger Read with Wells Fargo. Please go ahead.
Roger Read — Wells Fargo — Analyst
All right. Well, I’ll give my congratulations to you, David. Good luck with everything, and it’s got to be better than listening to people like us once every three months.
David R. Looney — Executive Vice President and Chief Financial Officer
It’s working for me, probably, yes. It is better than that…
Roger W. Jenkins — President and Chief Executive Officer
Thank you, Roger, and no comment on that.
Roger Read — Wells Fargo — Analyst
We don’t have thin skin, go ahead, let loose. Just kind of two questions to follow up on both on, I guess, kind of balance sheet and cash flow side. You talked earlier, Roger, about the dividend and restoring it. And I’m just curious, do you think about or does the Board think about it from a yield standpoint, a payout standpoint, payout relative to production? What would be maybe a base-level commodity price that they would want to think about? And then the other question I had was, can you give us an idea of what the benefits of achieving the IG rating will be to Murphy besides the obvious of just a lower cost of debt, like is there anything else we should think about from an operating or financial standpoint?
Roger W. Jenkins — President and Chief Executive Officer
Thanks for that question, Roger. Great question. On to our dividend, I mean, 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, cut to $0.50. Today, on an annualized basis we’re $0.70. Years ago in the prior uptime of oil, 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’re now moving beyond the pre-COVID level and beyond. I’ll 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 the ’12, ’13, ’14-time frame, we’re 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 ’21, which would require additional dividend increases throughout the year. Going into next year, same position again. And continue on that march get the dividend is in very, very good shape and then see where we are in our company around a consistent buyback program. And that’s where we’re headed and more of that in lieu of the yield. When you’re a big dividend payer and you want to be a dividend payer and you want to get back to that, that means more to us than a specific yield and stopping and that we see a lot of value creation. And two things for us, Roger. One is the equitizing. Equitizing our EV. And 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, and we think we’ll be in very, very well positioned with the assets we have, how we’re performing, how we’re executing and doing that long term. On the IG, I’ll let David address that. To me, we’ve never had a secured revolver at Murphy. We’ve never offered security for any type of debt in our company’s history. And when you have IG, we feel we can still continue to be unsecured, but it gives a lot more power beyond that. And I’ll let David talk about other advantages.
David R. Looney — Executive Vice President and Chief Financial Officer
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, etc. For years, we’re investment grade before things happened in the 2015, ’16-time frame, etc. 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, it 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, as everyone knows, Murphy has always been a globally oriented company and some of the projects that we get involved in, whether they be local or whether it be international, the counterparties and government entities, etc, are always looking for someone with a strong financial backing and obviously, that investment-grade rating means a lot when we get into those situations from the perspective of bonding issues,etc. So it’s just a — it 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.
Roger Read — Wells Fargo — Analyst
That’s great. Thanks guys.
Operator
[Operator Instructions] Your next question comes from Leo Mariani with KeyBanc. Please go ahead.
Leo Mariani — KeyBanc — Analyst
Good morning. I was hoping you all can 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?
Roger W. Jenkins — President and Chief Executive Officer
I think originally, our plans here — 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 field where we’re 50-50. We own 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.
Leo Mariani — KeyBanc — Analyst
Okay. So it definitely sounds like trending a little bit above expectation, certainly at this point.
Roger W. Jenkins — President and Chief Executive Officer
Yes, I would agree with that for sure.
Leo Mariani — KeyBanc — Analyst
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 11, I think you cited, but does it look like these things are trending a little bit above kind of some of the earlier type curves? Or it’s a little too early to tell?
Roger W. Jenkins — President and Chief Executive Officer
I’ll have Molly handle that question for you. Leo. She’s on top of that matter.
Molly Smith — General Manager
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 earlier, and they are performing above type curve. 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 were turning on more online 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 in very — it is very early, but we’re very excited about the wells coming online earlier and at higher results.
Roger W. Jenkins — President and Chief Executive Officer
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, I 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.
Operator
[Operator Closing Remarks]