Murphy Oil Corporation (MUR) Q1 2023 Earnings Call Transcript

Murphy Oil Corporation (NYSE: MUR) Q1 2023 Earnings Call dated May. 03, 2023

Corporate Participants:

Kelly Whitley — Vice President, Investor Relations & Communications

Roger W. Jenkins — President & Chief Executive Officer

Thomas J. “Tom” Mireles — Executive Vice President & Chief Financial Officer

Eric M. Hambly — Executive Vice President, Operations

Analysts:

Arun Jayaram — JPMorgan — Analyst

Neal Dingmann — Truist — Analyst

Paul Cheng — Scotiabank — Analyst

Neil Mehta — Goldman Sachs — Analyst

Charles Meade — Johnson Rice — Analyst

Leo Mariani — Roth MKM — Analyst

Presentation:

Operator

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corp. First Quarter 2023 earnings conference call. [Operator Instructions]

I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Kelly Whitley — Vice President, Investor Relations & Communications

Thank you, Joel. [Phonetic] Good morning, everyone, and thank you for joining us on our first quarter earnings call today. Joining me today is Roger Jenkins, President and Chief Executive Officer; along with Tom Mireles, Executive Vice President and Chief Financial Officer; and Eric Hambly, Executive Vice President of Operations.

Please refer to the informational Slides we’ve 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. Cautionary statement. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ.

For further discussion of risk factors, see Murphy’s 2022 Annual Report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.

I will now turn the call over to Roger.

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today.

On Slide 2, Murphy continues to deliver a strong value proposition to our shareholders. Our ongoing execution excellence across our significant offshore backlog and over 1,000 oil-weighted onshore locations will ensure that we will remain a long-term sustainable company. We operate safely with a focus on continual improvement in our carbon emissions intensity. Offshore competitive advantage is reinforced with our significant recent progress success — project success rather at our Khaleesi, Mormont, Samurai fields in the Gulf of Mexico.

Murphy also has an ongoing exploration portfolio as we’re in process of a three-well program operated this year. We continue to generate strong cash flow. We’ve been able to more than double our long-standing dividend from 2021 as well as significantly reduce long-term debt.

On Slide 3. As we advance our priorities to delever, execute, explore, and return, we remain focused on achieving our $500 million debt reduction goal for 2023, as we execute Murphy 2.0 of our capital allocation framework. The recognition of our debt reduction efforts over the past two years along with our great execution success, especially in the Gulf of Mexico, we recently received a credit rating upgrade to BB+ with a stable outlook from S&P Global.

Our efforts to — on maintaining strong well performance and uptime led to Murphy’s first quarter production volumes of 172.5 million [Phonetic] barrels equivalent per day exceeding the upper end of our guidance. We executed our onshore well program as planned with 15 operated wells online. In the Gulf of Mexico, our team brought online the Samurai 5 well obtained in the quarter, and we’ve been able — and the well has produced above expectations this past month.

Murphy also celebrated a significant milestone recently with the one-year anniversary of achieving first oil at King’s Quay. I’m pleased to say that the gross cumulative production on that facility in the first year was more than 30 million barrels equivalent. On the exploration front, we disclosed today the success of the Longclaw well and we’re awaiting results of two additional exploration wells later this year.

We also added to our exploration portfolio with six blocks from the recent Gulf of Mexico Federal sale. As we continue to support our shareholders through target returns, Murphy announced last month, we’ve been maintaining our quarterly dividend at $0.275 per share or $1.10 on an annualized basis, which we noticed is the highest rate since 2016. On Slide 4, exceeding guidance for the first quarter across all of our assets due to stronger well performance, production of 172.5 million equivalent per day, consisted of 94,000 barrels of oil per day, which represents a 25% oil growth since the first quarter of 2022, our highest first quarter production level since 2020.

In the Gulf of Mexico, we produced nearly 4,000 barrels equivalent per day above our guidance, as well as 1,100 barrels equivalent per day above guidance in Tupper Montney, along with 3,400 barrels equivalent a day of positive impact in the Tupper Montney due to lower royalty rates. We realized $74 a barrel for our oil. We had a realized NGL price of near $26 a barrel and that gas for us was $2.68 [Phonetic] per thousand cubic feet for the quarter.

I’m now going to turn the call over to our CFO, Tom Mireles, for an update on our financials and sustainability efforts. Tom?

Thomas J. “Tom” Mireles — Executive Vice President & Chief Financial Officer

Thank you, Roger. Good morning, everyone.

Slide 5. Our first-quarter net income totaled $192 million or $1.22 per diluted share. Including after-tax adjustments, adjusted net income was $195 million or $1.24 per diluted share. Our continued operational success generated strong cash from operations including non-controlling interest of $280 million, which also reflects $124 million of our contingent consideration payments made in the quarter.

After accounting for net property additions, we had negative adjusted cash flow of $66 million, which is a reflection of our forecasted capital program being heavily weighted to the first quarter. The remaining $48 million of our first quarter contingent consideration payments were reflected in the financing activity section of the cash flow statement.

These contingent consideration payments were related to two Gulf of Mexico acquisitions in 2018 and 2019 and were structured as revenue-sharing payments once certain thresholds were exceeded. The last revenue sharing contingent payments were made in the first quarter as reflected in our financial statements. Our final $25 million payment was made in April related to the one-year anniversary of first oil at King’s Quay, which fulfills all of Murphy’s obligations on these transactions.

Slide 6. We maintained a high level of liquidity in the first quarter of $1.1 billion, consisting of our $800 million credit facility and more than $300 million of cash and equivalents. I’m pleased that Murphy recently received a credit rating upgrade to BB+ with a stable outlook from S&P Global, reflecting our operational excellence and our commitment to debt reduction. Consistent with our priorities, we remain focused on achieving our $500 million debt reduction goal for 2023.

Slide 7. As part of our operational excellence, we are delivering on key sustainability initiatives. Our operations team is successfully reducing emissions through a variety of techniques. For example, we are replacing diesel with natural gas in our drilling and completion operations and installing more effective vapor recovery units in our onshore facilities.

Additionally, we are enhancing our water recycling and have recycled approximately 36% of our total frac volume in first quarter 2023 onshore completions. This represents a significant improvement from four years ago. Our efforts have been recognized, Murphy was recently named to Newsweek’s Most Trustworthy Companies in America 2023, as well as Best Place for Working Parents 2023 by the Greater Houston Partnership for a second consecutive year.

With that, I’ll turn the call over to Eric, our Executive Vice President of Operations to discuss our asset success.

Eric M. Hambly — Executive Vice President, Operations

Thank you, Tom, and good morning, everyone. Slide 9. Murphy’s first quarter Eagle Ford Shale production averaged 27,000 barrels of oil equivalent per day with 85% liquids. We brought online 10 operated wells as planned in Karnes, which included two successful refracs.

Additionally, we had seven gross non-op wells come online in the quarter across our Tilden and Catarina acreage. For the second quarter, we plan to bring online nine operated Catarina wells and eight operated Tilden wells, plus two non-op wells in Tilden. Over the past few years, our Karnes program has included a couple of refrac wells in conjunction with new development. I’m pleased that our 2023 wells achieved a 10-time production increase and delivered higher post refrac rates than the wells delivered at initial production.

As you can see on our chart reflecting Karnes lower Eagle Ford Shale performance, our average 250-day cubic per foot demonstrates the improvement we’ve seen with our enhanced completion design, which we’ve highlighted in previous quarters.

Slide 10. In the Tupper Montney, Murphy produced 292 million cubic feet per day in the first quarter and brought five wells online as planned. Our well delivery program continues in the second quarter with three planned wells. We maintain a price diversification strategy for a portion of our volumes that are not protected with fixed price-forward sales contracts.

For the first quarter 2023, we sold approximately 17% of our volumes at Malin, Chicago, Ventura, and Dawn pricing for an average US$6.65 per thousand cubic feet. No volumes were exposed to AECO prices in the quarter. As a result of this risk management strategy, we received an overall realized gas price of US$2.59 per a thousand cubic feet for the first quarter, which was approximately 9% above the AECO average.

Slide 12. Murphy produced 90,000 barrels of oil equivalent per day with 80% oil across its offshore assets in the Gulf of Mexico and Canada. Late in the quarter, we brought online the Samurai 5 well and have seen production exceeding expectations. We are excited to have recently celebrated the one-year anniversary of achieving first oil at King’s Quay and note the significant accomplishment of more than 30 million barrels of oil equivalent gross cumulative production in the first year. We also recently had another record gross production level of 126,000 barrels of oil equivalent per day, and we continue to average 97% uptime.

Our operating partner at Terra Nova continues to work on maintenance and commissioning activities in Newfoundland and Murphy maintains the view that it’ll be back online at year-end.

And with that, I will turn it back to Roger.

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Eric. On Slide 14, we’re pleased to announce we have today that Murphy’s operator drill to discovery at the Longclaw exploration well in Green Canyon 433 in the Gulf of Mexico. This well will be a tieback to our King’s Quay facility. We found 62 feet of net oil pay and are evaluating results the well just finished here just recently. Murphy held a 10% working interest while drilling Longclaw and received a 4.5% carry after casing. So after our election, we will hold 14.5% working interest in this well.

As previously disclosed, Murphy temporarily suspended drilling on the Oso #1 exploration well in Atwater Valley 138 in the Gulf of Mexico. We highlight that this is no indication of potential well results and Murphy intends to resume drilling in the third quarter of this year once the necessary managed pressure drilling equipment and required permits have been received.

Our operated Gulf of Mexico exploration program continues this year with our third well, Chinook 7, which is located in Walker Ridge 425. We spud this well just two days ago, and we anticipate the cost of $48 million net to Murphy. We estimate a mean to upwards gross resource potential of 50 million barrels equivalent to 120 million barrels equivalent from this well. If successful, we intend to tie this well into our nearby Murphy-operated cascade Chinook FPSO.

As we turn to Slide 16 on capital and production, as disclosed in our news release earlier this morning, we’re maintaining our 2023 capex guidance range of $875 million to $1.025 billion. We also reaffirm our full-year 2023 production range of 175.5 million [Phonetic] barrels equivalent per day to 183.5 million [Phonetic] barrels equivalent per day, which is 55% oil. Overall, this achieves a 10% oil growth from full year 2022 and 7% total production growth.

For the second quarter, we forecast an estimated production range of 173 million [Phonetic] barrels equivalent per day to 181 million [Phonetic] barrels equivalent per day with approximately 54% oil and 60% liquid volumes. Our forecast accrued capex for the quarter will be $320 million.

On Slide 17, as announced in 2022, Murphy has a multi-tier capital allocation framework that allows for additional shareholder returns beyond our quarterly-based dividend, while advancing toward a long-term debt target of $1 billion. We maintain a broad — a Board rather authorized initial 300 million share repurchase program along Murphy to repurchase shares through a variety of methods with no time limit. As of today, we have not executed any repurchases under that authorization.

On Slide 18, we’ve continued our disciplined strategy to delever, execute, explore, and return. And our near-term plan is to reduce debt by $500 million this year, assuming a $75 per barrel oil price, with approximately 40% of operating cash flow reinvested annually through 2025 based on an average capital amount of $900 million per year. We forecast that this will maintain an average 55% oil weighting with production averaging 195,000 equivalents per day, representing a combined annual growth rate of 8% through 2025, while also supporting our targeted exploration program.

As part of this plan, offshore production will be maintained at an average of 90,000 barrels equivalent per day to 100,000 barrels equivalent per day in that period. Overall, we’ll continue to utilize excess cash flow as we execute our plan of enhancing payouts to shareholders through dividend increases and share buybacks as laid out in our capital return framework.

Longer term in ’26 and ’27, we see Murphy maintaining a sustainable business and targeting investment-grade status, where we forecast average annual production of approximately 210,000 barrels equivalent per day at 53% oil weighting. Additionally, our ongoing reinvestment rate will remain low at 40% of our operating cash flow, and we’ll have ample free cash flow generated from this plan to fund further debt reductions in our capital allocation framework and enhance shareholder returns as well as fund high returning investment opportunities.

On Slide 19, on strategic priorities, looking forward for the remainder of 2023, Murphy is well positioned to execute our Murphy 2.0 capital allocation framework plan. Our strong Gulf of Mexico business continues to lead the way with great execution and well performance and is supported by our multi-decade sustainable onshore business. We also have two additional key exploration wells to drill this year and we look forward to reviewing those results with our investors.

In closing, I’d like to thank our great employees for their hard work this quarter as we beat across the Board on every number. And we’ve very successfully executed our plans with their efforts.

Now, I will turn the call over to everyone for their questions. Thank you.

Questions and Answers:

 

Operator

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] Your first question comes from Arun Jayaram with JPMorgan. Please go ahead.

Arun Jayaram — JPMorgan — Analyst

Good morning, Roger.

Roger W. Jenkins — President & Chief Executive Officer

Good morning, Arun. Good to hear from you.

Arun Jayaram — JPMorgan — Analyst

Yes, I was wondering — yes, good to hear from you as well. Roger, I was wondering if you could give us a little bit more details on the 2023 program in the Gulf of Mexico. You highlighted the drilling of Chinook #7 as well as a planned return to Oso, and perhaps you could also just discuss some of the inventory you added through the recent lease sale in the Gulf of Mexico?

Roger W. Jenkins — President & Chief Executive Officer

Yeah, thanks for that question about all that. We had a very good lease sale. We just finished up this Longclaw well, just finished drilling the well, not even a week ago or five or six days ago, on which we had success. Oso is a well we’ll be returning to in the third quarter. We have a plan from our team to execute that well with some additional equipment that we need. I would also comment that the Oso area was quite active in the lease sale. There’s a new data set being shot in that region, and it was a lot of activity around that Oso area. We were also active there and we were successful there. We had a very successful lease sale in that area and up near the Delta House area where we had a lot of competition, we were able to have success on all of our competitive blocks, but one, so really good lease sale and a big nice inventory, especially around Delta House and especially around Oso.

The Chinook well is a well we have been planning for a very long time. This is a significant undrilled fault block near Cascade Chinook field that we purchased from — our port [Phonetic] formed a JV rather with Petrobras years ago. It comes with an FPSO that sits in that field, a very highly successful FPSO with incredible cost structure and uptime, a real asset for us. We’ve had this well in our books, had to work out some things with our partners, and announced to spud that well yesterday, and really excited about that well.

We do have a backlog of other opportunities, I’ll have Eric address involving development here. Eric, why don’t you update Arun on that?

Eric M. Hambly — Executive Vice President, Operations

Okay. Thanks, Roger. As we highlighted on our last quarterly call, we have been working over the last several years with some of our recently-acquired fields and have come up with a number of projects, and as we highlighted in our last quarter, we have quite a nice running room of offshore projects that will perform over the next five to seven years, including 26 projects with 125 million barrels of total resource that have a breakeven of less than $35 a barrel WTI.

So we’re pretty excited about our development opportunities as well as the exploration opportunities that Roger highlighted.

Roger W. Jenkins — President & Chief Executive Officer

But with the ongoing activity room, we’ll be bringing on Dalmatian well later this year and drilling, and hopefully, completing the Marmalard well probably that probably just really can’t flow much right at the end of the year.

Eric M. Hambly — Executive Vice President, Operations

Should flow early in ’24.

Arun Jayaram — JPMorgan — Analyst

Great. And Roger, I wanted to see if you could give us an update on your plans in non-op and operated plans in Canada, you highlighted two wells at Hibernia. And can you give us an update on what you’re hearing from the operator at Terra Nova? I think you expect the project to start online by year-end.

Roger W. Jenkins — President & Chief Executive Officer

I’d normally let Eric handle this but it’s quite simple. We reviewed the project and we believe it can flow at year-end and we believe it’s better to provide investors a timing rather than an open-ended type dialogue. And we’re hopeful to work with them more ahead and engage with them and that we feel that that project will flow at near year-end. It is not going to be a significant part of our volume if it does not, but that’s our status on that today. Hibernia, an all time great field for us and have a couple wells there planned.

I will say as we frame and talk about Terra Nova, and your commentary this morning, you noted about the well-discussed Terra Nova. We have made $1.2 billion of free cash flow at Terra Nova at only a 9% working interest, and now we have a larger working interest that’s funded primarily to a government deal. This is an incredible project; this project will come online; this project will have incredible high return. Hibernia too made almost $3 billion of free cash flow itself.

So these are significant successful long-term fields for us, and we’re well-positioned there to make a lot of free cash flow in East Coast Canada.

Arun Jayaram — JPMorgan — Analyst

Great. Thanks a lot.

Roger W. Jenkins — President & Chief Executive Officer

Thank you.

Operator

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

Neal Dingmann — Truist — Analyst

Good morning. Thanks for the time. Roger, my first question also on offshore. I’m just wondering, you’ve been successful I guess last year and even other years just on adding very accretive working interest and other things like that offshore. I’m just wondering, could you talk about, kind of what Arun was asking, I’m wondering how you would balance. You’ve got obviously the positive things going on at King’s Quay, you’ve got some interesting exploration. I’m just wondering how you would balance, or have you seen some additional working interest or other opportunities within those two?

Roger W. Jenkins — President & Chief Executive Officer

That’s a good question, Ryan, and thank you for asking about our successful efforts in the Gulf of Mexico. We really don’t have a hot-running working interest purchase today, quite frankly. And we’re really executing our backlog of offshore wells and our long-standing inventory of onshore wells along with the framework today; not the capital allocation framework but our long-term plans that I disclosed just a few minutes ago in my commentary. We want to keep that capex in that range, continue to have this modest growth and we’ll be picking and choosing between our long-term projects in the Gulf, and a very significant success in Eagle Ford as well. And be maintaining these oil rates. And just have multiple ways to make the same return and real proud of our inventory in both off and onshore. We got offshore inventory too, and Eric’s done a great job at pulling it together. And we’re going to be executing it like on Slide 12, this year. There’ll be another slide like that next year, and we’re happy with where we are on having the assets to sustain our plan and be successful, and we are. [Phonetic]

Neal Dingmann — Truist — Analyst

Great point. And then, Roger, maybe for you or Tom, just second on free-cash-flow allocation. I believe your debt targets are on a gross, not net basis. So, really looks on reducing debt instead of just adding cash to the balance sheet. And so I know in the past you’ve talked about maybe wanting a minimum cash balance of, I don’t remember, it was about $400 million or so for M&A and discoveries. So, I’m just wondering, given what price — what’s going on with prices and your announced recent discovery, I’m just wondering — and I know you’ve got this Murphy 2.0, would you all consider foregoing one to two quarters of debt reduction in favor of cash build or how do you sort of see that plan going forward?

Thomas J. “Tom” Mireles — Executive Vice President & Chief Financial Officer

No, the way we’re thinking about it, Neal, is we’re going to really focus on getting to that long-term debt target. So, our priority right now is to any adjusted free cash flow, we’ll stick to the framework and focus on reducing that — that debt. As you saw in our in our financials, we are kind of front-loaded here with our capital, so it’s probably more of an activity we’ll see in the second half of the year starting to reduce that debt within the adjusted free cash flow we have.

Neal Dingmann — Truist — Analyst

Okay. Thanks, Tom. [Speech Overlap]

Roger W. Jenkins — President & Chief Executive Officer

I have a little bit of color to add to that, Neal. I think it needs to be pointed out, if you look at our cash flow statement today, yes, our cash went down about the same amount of the contingent payments, so we’re talking about paying contingent payments into a very successful M&A, which there was a revenue share and which we’ve received the other half. Also, all of this M&A is completely paid out, including acquisitions have been paid out; at least the Mormonts have been paid out; Delta House have been paid out. So we have paid out assets, and if we have a severely frontloaded capital and without contingent payments, we would have had cash flow neutral. I think that’s very positive for us. It sets us up in the second half to really execute on this framework that we have.

Neal Dingmann — Truist — Analyst

That’s a great point. Thanks, Roger.

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Neal. Good to hear from you.

Operator

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

Paul Cheng — Scotiabank — Analyst

Hi. Good morning, guys.

Roger W. Jenkins — President & Chief Executive Officer

Good morning, Paul.

Paul Cheng — Scotiabank — Analyst

How are you doing?

Roger W. Jenkins — President & Chief Executive Officer

Doing good.

Paul Cheng — Scotiabank — Analyst

A number of quick questions. Maybe the first one, just administrative, that AECO Contingency payment, when it is going to show up in the cash flow statement, just in the financing activities, or just in the cash flow from operation?

Roger W. Jenkins — President & Chief Executive Officer

I’m sorry, Paul. You mean the contingent payments have already been paid. There is one additional payment as we disclosed in our release of $25 million. [Speech Overlap] We’ve already paid — we’ve already paid it this month. I’m not — [Speech OIverlap] where is it, Thomas? It will be an operating cash flow, I would assume.

Thomas J. “Tom” Mireles — Executive Vice President & Chief Financial Officer

So, it will also be split a little, little bit between operating [Speech Overlap]

Roger W. Jenkins — President & Chief Executive Officer

It’d be split between financing, operating. And that’s due to the original setup of the M&A deal in our accounting, Paul.

Paul Cheng — Scotiabank — Analyst

Okay.

Roger W. Jenkins — President & Chief Executive Officer

But that’s — after that, this stuff is over, Paul, for all that.

Paul Cheng — Scotiabank — Analyst

No, I understand. We’re just saying that because I think that the investors will be looking at CFFO number more closely typically. So we want to know right now whether that — that $25 million is going to be in there or just going to be in the financing activity line.

Second one, Roger, that in post-2026, once you get to 200,000 barrel per day to 220,000 barrel per day kind of range, what’s the sustaining capex requirement going forward?

Roger W. Jenkins — President & Chief Executive Officer

I believe it’s disclosed in that Slide, Paul. Turn to that, Megan, [Phonetic] please. The — in the ’26, ’27 period, I would anticipate it to be in the similar level that we are on the left-hand side of that Slide, in the $900 million [Phonetic] level — $900 million, $950 million [Phonetic] is my expectation for that, Paul.

Paul Cheng — Scotiabank — Analyst

Okay. And then a final one from me, on the longer term, how’s your marketing strategy for Montney? I mean, why now that you have majority of them sold under fixed — long-term contract, and then the rest is due the different part in the US and no spud exposure? Should we assume that that will be essentially the best strategy going forward?

Roger W. Jenkins — President & Chief Executive Officer

I’m going to let Eric give you color on that, Paul, please.

Eric M. Hambly — Executive Vice President, Operations

Okay, Paul. We have, as you noted, we through 2022 to 2024, put in place a number of fixed forward sells related to our Tupper Montney project. So we, as you know, we increased the capacity of our plants there by 200 million cubic feet per day, and we’ve had a multi-year program of adding a slightly higher level of activity to get those plants full, which we expect probably by the second half of 2024.

In order to support that additional capital allocation to the asset, we’ve put in place some fixed forward sells to make sure that we would generate free cash flow from the asset while growing. If you look beyond 2024, we are very unlikely to put in place fixed forward sells like that, but we are likely to maintain a diversification strategy where we’ve proven over quite a long time now, a decade or so, that we’ve been able to get enhanced prices by diverse sales into various U.S. markets like Malin, Chicago, Ventura and Dawn. That’s something that will likely feature in our program going beyond 2025.

And then we’re also looking opportunistically to participate in any kind of value-creation that might be driven by LNG projects coming online in Canada or additional gas that needs to come into the Gulf Coast to the U.S. for LNG. So we’ll evaluate all of those and have sort of a diverse strategy that maximizes our free cash flows.

Paul Cheng — Scotiabank — Analyst

Just curious that when you sign long-term contracts or that is really going to be decided on a month-to-month basis in terms of which market you’re going to sell to?

Eric M. Hambly — Executive Vice President, Operations

What I would expect there, Paul, is a combination of contracts that are based on locking in a differential with transportation from AECO to those diverse markets, and other different kinds of arrangements that — as we can find the best outcome, best deal.

Paul Cheng — Scotiabank — Analyst

Okay. Thank you.

Operator

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

Neil Mehta — Goldman Sachs — Analyst

Hey. Thanks for [Speech Overlap]

Roger W. Jenkins — President & Chief Executive Officer

Good morning, Neil.

Neil Mehta — Goldman Sachs — Analyst

Good morning, Roger. Congrats on a good quarter here from an execution standpoint. I know, you spent a lot of time talking about 2023 and it’s early to talk about ’24, but [Speech Overlap]

Roger W. Jenkins — President & Chief Executive Officer

Yeah, real well [Speech Overlap]

Neil Mehta — Goldman Sachs — Analyst

[Speech Overlap] — I would imagine you — yeah, real, all right. I recognize that, but I would imagine there some moving pieces that you wanted us as the investment community to get our heads around as it relates to production. So, how should we — any early thoughts and guidance you can provide on ’24, and at an asset-level, would be great.

Roger W. Jenkins — President & Chief Executive Officer

Well, thank you, Neil, for that question. Our long-range plan is not even Memorial Day, and you like trying to gauge questions on holidays. Just finished Easter here. And so I was asked for our page that we have here, we have an averaging capex shown in our deck here today around $900 million. That means that capex next year at this time, and in that plan, was a little bit less than this year. We’d hope to keep that similar to what we have this year. We do have a lot of backlog of offshore, we do have success today at Longclaw. That will take the place of some of our backlog, if you will, at the point of when we want to do that.

And so I would say it’s a similar year to next year with higher production because we will have all of our new backlog wells online. Dalmatian this year, Marmalard next year. I’d assume it to be a year similar to this with our production, higher oil production and higher overall production.

Neil Mehta — Goldman Sachs — Analyst

Thanks, Roger, for indulging there. Then the follow-up, there’s been a lot of talk about offshore cost inflation. We’re seeing some early signs, hopefully, deflationary forces in U.S. land, but offshore, it’s still a lot of upward pressure. So can you talk about how you’re mitigating it, and are you seeing anything green shoots when it comes to the inflationary pressures?

Roger W. Jenkins — President & Chief Executive Officer

Yeah, thanks, Neil. We’ve been preparing our answer, and I’m going to let Eric speak to you about that this morning.

Eric M. Hambly — Executive Vice President, Operations

Okay, thanks. Neil, the big driver for our costs for offshore is really rig rate, and we’re sort of advantaged this year and we’re really happy with how we’re set up for 2024 and into 2025. So for about half of our program, offshore in 2023, we have a significantly below market rig rate which we locked in, so around 300,000 a day. The rest of the program, we have locked in pricing, all the way through the end of ’23, 2024, and the first part of ’25, at what is effectively market rate right now, which is around 430,000 a day for a drillship.

So we’re pretty happy with that and that should be the main component of something that could be inflationary for us. We have it locked in through early ’25. Really happy with that.

Neil Mehta — Goldman Sachs — Analyst

Good stuff, guys. Thank you.

Roger W. Jenkins — President & Chief Executive Officer

Thank you Neil. Appreciate it.

Operator

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

Charles Meade — Johnson Rice — Analyst

[Speech Overlap] Good morning, Roger, to you. Good morning. I wanted to ask a question about these Karnes refracs. So it is really intriguing to me that you had higher IPs than the initial — than I guess the initial completion, but I wonder if you could add a few more coordinates to that? And I’m thinking — what was the — what’s the decline profile look versus the original decline profile, and how maybe the completion design or intensity versus the original completion? And whether you’re planning on doing more of these in ’23?

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Charles. Eric’s the guy that came up with this plan, and I’ll let him tell you about it.

Eric M. Hambly — Executive Vice President, Operations

Okay. Thanks, Charles. We’ve identified 220 wells across our Eagle Ford Shale position, which we think are likely to be good candidates for refracs. And the way we came up with that was we looked at wells that were initially — were initially fractured with less than 1,200 pounds per foot of proppant. If you compare that to our current completion design of 2,800 pounds per foot to 3,400 pounds per foot, they look quite a bit under-stimulated.

Over the last three years, our refrac activity has been focused in Karnes and associated with new development. So we go into an area where we plan new wells and we refrac old wells, which we think that that’s helping improve the performance of our new wells. And also, as we highlighted on our call today, we’re getting nice production uplift and reserve recovery from those refracs. They’re pretty exciting. We’re seeing rates go from 15 barrels a day to 20 barrels a day to up to 1,500 barrels a day, initially. That’s not an IP30, that’s more of a peak.

The decline profile is not that dissimilar from initial production from those wells when they first came online, maybe seven or eight years ago. So it looks like a good opportunity for us. What we do in those wells is we run a four-inch casing, we go and perf and frac, kind of like a new well, just a little bit skinnier whole, and we’ve had great success with it. We’re really excited. We are currently evaluating what might become a standalone program to address that 220-well inventory of refracs. That’s not been our current mode but that’s something that we’re looking at. Hope that helps you give a little background on what we’re trying to do there.

Charles Meade — Johnson Rice — Analyst

That’s a lot of great detail. Thank you, Eric. And my second — my follow-up question, Roger, is — it’s about the King’s Quay facility. And I went back and looked, and I guess the nameplate on that as originally designed was more like a 102 BOE a day. And so you guys are something north of 20% over that with this rate you disclosed today.

So are you guys — what should we expect going forward? It would seem to me that you’re kind of knocking up against a ceiling of what that facility could do and perhaps we should expect some kind of reversion back to nameplate capacity over time, but perhaps that’s not the case. I wonder if you could elaborate on that.

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Charles, for asking that question. It’s a big homerun feel for us, one of the greatest in company history for us. It’s going to be difficult, very difficult to produce more than that headline we had today. Our equipment is running at the max. So just keep in mind that when we purchased this project and executed this project through COVID, that there’s another field in the Gulf called Delta House. It’s a very similar facility that has multiple fields flowing throgh, that we also operate. And that field also has been able to go over the nameplate, and our team was able to learn from that as we operate that and take this over nameplate.

We’re probably not going to see production levels from that, but we’re very happy about where we are. And also keep in mind that Samurai is a field that’s 50% working interest for us. And when Samurai does well, we do well, and the field’s doing well and going to be on plateau here into 2025. And it’s going to be some additional probably things that we’re finding to do in that area. Samurai gets better, bigger every day, so big home-run ball, probably can’t make much more production than that, but that’s still a lot of production out of eight wells.

So, we’re really, really proud of it and thanks for noting that.

Charles Meade — Johnson Rice — Analyst

Thank you for the detail, Roger.

Roger W. Jenkins — President & Chief Executive Officer

You broke up, Charles. I’m sorry.

Charles Meade — Johnson Rice — Analyst

No, that — I was just saying thank you for that detail. That’s it from me.

Roger W. Jenkins — President & Chief Executive Officer

I thought you said — I thought you wanted more detail, Charles. I’d say, wow.

Charles Meade — Johnson Rice — Analyst

Another time.

Roger W. Jenkins — President & Chief Executive Officer

Appreciate you calling in.

Charles Meade — Johnson Rice — Analyst

All right.

Operator

[Operator Instructions] Your next question comes from Leo Mariani with Roth MKM. Please go ahead.

Roger W. Jenkins — President & Chief Executive Officer

Good morning, Leo. Thanks for calling in.

Leo Mariani — Roth MKM — Analyst

Yeah, good morning. I was hoping to get a little bit more color around the exploration program here in the Gulf. Just on the Longclaw well, you guys announced it as a discovery, but at the same time, I guess you said you’re still evaluating it. It’s got 62 feet I guess of net pay, which I know it’s not the only metric, but it doesn’t seem enormous at this point. Just trying to confirm is this, in fact, definitely a discovery, just given that it sounds like it’s a close subsea tieback, probably won’t require a lot of capital?

And then just on the Chinook well, wanted to see if we can get a little bit more color in terms of kind of rough drill time on this, and what the risk profile on this thing is? Is it a true exploration well, kind of one-in-five type well in terms of the expectation? Just any color on that would be great.

Roger W. Jenkins — President & Chief Executive Officer

Thanks for that question, Leo. No, absolutely, when we say a well’s a discovery, then we anticipate on producing that well, and we anticipate increasing our working interest on that well. It’s — the issue is the size of it; not issue as we’re working it. I’d say it’s a 10-million-barrel to 20-million-barrel discovery, but you’re talking about a 50-yard tieback from here to my office to flow this well into one of the most successful platforms in the Gulf, with manifolds pipes in place. So the economics of this, similar to Samurai, which are incredible, this will have a incredible economic. And also, as we operate other fields and operate King’s Quay, a new set up well for — not involved with the original field, will lower the operating expenses across the whole platform for us. And well, this is a very positive for us. Is it a massive oilfield? No. But we can make a lot of money and do well here and work with our partners and we were able to be carried in the well a little bit, and we’re hoping to be able to do that in other places because of our — we have — we’re a top executing company, Leo, in the Gulf.

Onto Oso, it is — not Oso, I’m sorry, Chinook 7, it is in a field that’s been drilled, many wells there. You can see the — the number 7, if you will. I would say it’s a little better than a one-in-five exploration well. It isn’t a totally undrilled fault block. A lot of these major Wilcox fields such as St. Malo, and also here, Cascade Chinook and many others in the Gulf, have two big features to them, with a large fault down the middle of the field. Just so happens, still not been tested. We looked at this and compared it to other wells that have been drilled on both sides of major faults to these facilities, I mean, through these type plays, and we have a big nice well to drill here that can make this project last out till 2040. The FPSO, there is a very, very highly operated, efficient FPSO. We can move the crude off that FPSO where we need to in the Gulf Coast with tankers.

So it comes to the positive differentials and in many positive things for us. So, it’s near the field, but in a totally untested fault block, and that we’re very happy to be drilling that well and have a chance to again add more to our backlog. The well could get very large in size, or quite multiple wells if successful, or could be a simple tieback.

So real happy about it. And I thank you for asking us about it.

Leo Mariani — Roth MKM — Analyst

All right. That’s helpful. And then just on the sort of free cash flow use this year in the second half, it sounds like you’re very focused on paying down debt. I imagine that there’s probably going to be some takeouts if some of these existing bonds, kind of, like you’ve done in the past with some tenders here. But just in kind of light of sort of lower oil prices here, does this make the share buyback kind of fairly unlikely here in ’23 with the focus on debt reduction, that we need oil prices to kind of go up before maybe you buyback shares? I mean, just kind of talk about the dynamic between those two.

Roger W. Jenkins — President & Chief Executive Officer

I’m going to let Tom add all the color. But our framework, as we set up, has a portion to buyback or advance returns, which we assume to be bought back with debt reduction, so we can end up with less if oil prices are lower, but there is no plan to not buyback at all and due to all debt due to this pullback with the Fed and all that today, Leo.

And I’ll let Paul — I’ll let — I’m sorry, I’ll let Tom give you some more information on that.

Thomas J. “Tom” Mireles — Executive Vice President & Chief Financial Officer

Yeah. And that’s basically it, Leo. We’ll stick to our framework. And as we get into this next phase here, it’s definitely going to be splitting between 75% going to debt reduction and 25% going to share repurchase. So we just pulled back in oil prices. Maybe the quantums will be a little bit smaller than what we would have planned at $75 WTI, but that still is what we’re planning to do following our framework, 75%, 25% between debt reduction and share repurchase.

Leo Mariani — Roth MKM — Analyst

Okay. That’s helpful. And then just on your production volumes. Obviously, you’ve got second-quarter guidance here. Very much appreciate the detail there, but just kind of in the rest of the year, can you kind of help us out a little bit with kind of the high-level sort of cadence here? Do we see Gulf of Mexico volumes in 3Q maybe kind of flat to down with just hurricanes likely here in terms of the way you guys are thinking about it? And then kind of a nice ramp in 4Q, then I imagine that onshore, you’re going to see the nice ramp in 3Q as you get the benefit of kind of more wells coming on? Just kind of any help on production cadence in third quarter and fourth quarter, and just kind of the big moving pieces here?

Roger W. Jenkins — President & Chief Executive Officer

Well, if you look at our guidance today for the second quarter, making a little bit less in the Gulf of Mexico though. We have to shut in King’s Quay for a few days here coming up to do a turnaround of some equipment we need to update there.

And then actually in our lineup, the third quarter, while under a big hurricane downtime, still is higher than the second quarter and a big end of the year. So I’d say, as you know, right now we’ve guided 80 to 81 here in the second quarter, probably trying to get close to 83 in the third quarter, a little higher possibly, and maybe 90, a little more 90 in the fourth quarter there, Leo.

Eric M. Hambly — Executive Vice President, Operations

Yeah, Leo, just a bit of background, and I think we’ve noted before that our onshore program is pretty heavily weighted to new wells coming online in the second and third quarter. So you’ll see more growth onshore heading into the third quarter, and then more growth offshore heading into the fourth quarter as we bring online Dalmatian, Terra Nova. The Dalmatian new well, DC 90 well, and Terra Nova restart along with less weather downtime assumed in the third quarter.

So, third and fourth quarters aren’t that dissimilar from a total production rate, with a little more growth from second quarter onshore in the third quarter, and a little more growth offshore in the fourth quarter.

Leo Mariani — Roth MKM — Analyst

Okay. That’s very helpful, guys. Thank you.

Roger W. Jenkins — President & Chief Executive Officer

Appreciate it. Take care.

Operator

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

Paul Cheng — Scotiabank — Analyst

Hey guys. [Speech Overlap]

Roger W. Jenkins — President & Chief Executive Officer

You’re back, Paul.

Paul Cheng — Scotiabank — Analyst

Yeah, I just want to clarify. Eric, when you were talking about the refrac, those opportunities, 220 wells, that’s not included in your current 1,100 wells in the Eagle Ford, right?

Eric M. Hambly — Executive Vice President, Operations

That’s correct. Those are wells that are already producing, they’re not included in our 1,100 wells of remaining Eagle Ford inventory, to be addition to that.

Paul Cheng — Scotiabank — Analyst

All right. Thank you. And that I want to — just curious that in Longclaw, you only have 10% interest, and you’re the operator which is quite unusual for someone with a small percentage like that to be the operator. Is there any game plan in there that we’ll be able to have some arrangement for you to push the interest or that, I mean, this interest is — I mean, I’m just curious that why you would pick the operatorship there.

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Paul. You can operate things at 10%, Paul, when you’re real, real good, and we’re real, real good. So that’s — that’s kind of how that goes. This is a long-term prospect that was known when we purchased the field Khaleesi, Mormont, and we had our significant discovery at Samurai next door. Several of the partners that are in the field own this opportunity. They came to us to participate in the well. And if you notice in our — in my commentary, in my script commentary, we had an ability to increase our working interest post the well being cased, that which we’re going to do. So we have an ability to go up to 14.5%.

This well is — is this team that built this prospect really respects our company as an operator. We also have this work going on up in the middle of our most valuable field that we’ve ever owned probably. And so we want to operate and ensure operations out in the middle of King’s Quay and Samurai. This is located very near. It’s also very near we decided to put the well near one of the production manifolds. So our equipment and a lot of our company’s value is there.

So we wanted to operate even at a smaller working interest and we see it as an ability to control the field, operate the field efficiently, safely, and increase our working interest due to our operating scale and then lower the operating expenses of the facility. So it’s a win across the board for us and the partners are — great relationship with these partners, and they see us as a good operator, and we executed the well farm at a low working interest and everybody wins today, Paul.

Paul Cheng — Scotiabank — Analyst

All right. Thank you.

Roger W. Jenkins — President & Chief Executive Officer

Thank you.

Operator

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

Roger W. Jenkins — President & Chief Executive Officer

I appreciate everyone dialing in today. Appreciate the questions from our key analysts today. It was a good commentary back and forth, and really appreciate that support. And that we’re here executing another quarter and we’re doing very well. I’m very proud of how we’re running our business today, and we’ll be talking to you all soon. Take care.

Operator

[Operator Closing Remarks]