Murphy Oil Corp Q1 FY2023 Earnings Call

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corp. First Quarter 2023 Earnings Conference Call. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Thank you, Joel. 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 have placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves, and financial amounts are adjusted to exclude non-controlling interest in the Gulf of Mexico. Cautionary statements, 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 discussions 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.

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 remain a long-term sustainable company. We operate safely with a focus on continual improvement in our carbon emissions intensity. Our offshore competitive advantage is reinforced with our significant recent project success at Khaleesi, Mormont, and Samurai fields in the Gulf of Mexico. Murphy also has an ongoing exploration portfolio as we are in the 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 maintain strong well performance and uptime led to Murphy's first quarter production volumes of 172.5 thousand 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 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 at 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 that we are maintaining our quarterly dividend at $27.5 per share or $1.10 on an annualized basis, which is the highest rate since 2016. On Slide 4, we exceeded guidance for the first quarter across all of our assets due to stronger well performance. Production of 172.5 thousand equivalent per day consisted of 94,000 barrels of oil per day, which represents a 25% oil growth since the first quarter of 2022, and 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 per 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 gas for us was $2.68 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?

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 generates 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 are 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 the first quarter of 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.

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 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.

Thank you, Eric. On Slide 14, we’re pleased to announce today that Murphy’s operator drilled a discovery at the Longclaw exploration well in Green Canyon 432 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 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 a 14.5% working interest in this well. As previously disclosed, Murphy temporarily suspended drilling on the Oso number one 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 a cost of $48 million net to Murphy. We estimate a mean to upwards gross resource potential of 50 to 120 million barrels equivalent from this well if it is 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 175,000 to 183,500 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 173,000 to 181,000 barrels equivalent per day with approximately 54% oil and 60% liquid volumes. Our forecasted 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 Board authorized initial $300 million share repurchase program allowing 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. 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 of 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 to 100,000 barrels equivalent per day for 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 2026 and 2027, we see Murphy maintaining a sustainable business and targeting investment grade status. 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, looking forward for the remainder of 2023, Murphy is well positioned to execute our Murphy 2.0 capital allocation framework plan. Our strong Gulf 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 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. We’ve very successfully executed our plans with their efforts. Now, I will turn the call over to everyone for their questions. Thank you.

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

Good morning, Roger.

Good morning, Arun. Good to hear from you.

Yes, 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 number 7 as well as a plan to return to Oso, and perhaps you could also discuss some of the inventory you added through the recent lease sale in the Gulf of Mexico?

Yes, thanks for that question about all that. We had a very good lease sale. We just finished up this Longclaw well, which we had success drilling not even a week ago. Oso, as 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 dataset being shot in that region, and there was a lot of activity around that Oso area. We were also active there and we were successful. 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 nice inventory, especially around Delta House and Oso. The Chinook well is one we have been planning for a long time. This is a significant undrilled fault block near our Cascade, Chinook field that we purchased from our joint venture 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 and had to work out some things with our partners, but we now spud that well yesterday and we are real excited about that well. We do have a backlog of other opportunities. I’ll have Eric address those developments.

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

With the ongoing activity, Arun, we will be bringing on the Dalmatian well later this year and drilling and hopefully completing a Marmalard well, but probably just really can’t flow much right at the end of the year.

Should flow early in 2024.

Great. And Roger, I wanted to see if you could give us an update on your plans for non-op and operated plans in Canada that you highlighted two wells at Hibernia. 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 back up by year end.

I would 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 with a timing rather than an open-ended type dialogue. We are hopeful to work with them more ahead and engage with them, and we feel that project will flow 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 is an all-time great field for us, and we have a couple wells there planned. I will say as we frame and talk about Terra Nova in your commentary this morning, you noted about the well discussed at Terra Nova. We have made $1.2 billion of free cash flow at Terra Nova with only a 9% working interest, and now we have a larger working interest that’s funded primarily through a government deal. This is an incredible project and will come online. This project will have incredible high returns; 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.

Great, thanks a lot.

Thank you.

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

Good morning, all. Thanks for the time. Roger, my first question is also on offshore. I’m just wondering, you've been successful last year and even in other years just on adding very accretive working interest and other things like that offshore. I’m just wondering, could you talk about 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 maybe seeing some additional working interests or other opportunities within those two?

That’s a good question, Neal. 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 that we’re really executing our backlog of offshore wells and our longstanding inventory of onshore wells, along with the framework that I disclosed just a few minutes ago in my commentary. We want to keep that CapEx and that range continue to have this modest growth, and it’ll be picking and choosing between our long-term projects in the Gulf and our very significant success in Eagle Ford as well, and maintaining these oil rates; just have multiple ways to make the same return. I’m really proud of our inventory both offshore and onshore. We also have 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 I’m real happy with where we are on having the assets to sustain our plan and be successful.

Great point. And then Roger, maybe for you or Tom, just a second on free cash flow allocation. I believe your debt targets are on a gross net basis, so it really looks like you're focused on reducing debt instead of just adding cash to the balance sheet. I know in the past, you’ve talked about maybe wanting a minimum cash balance of about $400 million or so for M&A in discoveries. So I’m just wondering, given the price situation, 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 consider foregoing one to two quarters of debt reduction in favor of a cash build, or how do you sort of see that plan going forward?

The way we are thinking about it, Neal, is we’re really going to focus on getting to that long-term debt target. So our priority right now is to utilize any adjusted free cash flow. We’ll stick to the framework and focus on that debt reduction. As you saw in our financials, we are kind of front-loaded here with our capital. So it’s probably more activity we’ll see in the second half of the year starting to reduce that debt with any adjusted free cash flow we have.

Pretty good. Thanks, Tom.

I have a little bit of color to add to that, Neal. I think needs to be pointed out. If you look at our cash flow statement today, yes, our cash went down about the same amount as the contingent payments. So we’re talking about paying contingent payments into very successful M&A, which there was a revenue sharing, that we received. The other aspect is all this M&A is completely paid out, including acquisition, and have been paid out over least the months before. Delta House has been paid out. We have paid out assets, and if we have a severely front-loaded capital and without contingent payments, we would have had cash flow neutral. I think that’s very positive for us and sets us up in the second half to really execute on this framework that we have.

That’s a great point. Thanks, Roger.

Thank you, Neal. Good to hear from you.

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

Hi.

Good morning, Paul.

Good morning, guys. How are you doing?

Doing good.

A number of quick questions. Maybe the first one, just administrative; that April contingency payment, when is it going to show up in the cash flow statement? Are you seeing it in the financing activities, or yes, in the cash flow from operations?

I’m sorry, Paul. You mean the contingent payments have already been paid? There’s one additional payment as we disclosed in our release of $25 million. We’ve already paid it this month. I’m not sure where it will be, Tom.

It will be split a little bit between operating and financing.

But that’s all over, Paul, for all of that.

No, I understand. We are just saying that because I think that the investors will be looking at the cash flow from operations number more closely typically. So we want to know whether that $25 million is going to be in there or it’s going to be in the financing activity line.

Second question, Roger; that imposed 2026, once you get to 200,000 to 220,000 barrels a day kind of range, what’s their sustaining CapEx requirement going forward? I believe it’s disclosed on that slide. In the 2026, 2027 period I anticipate it to be in the similar level that we are on the left-hand side of that slide in the 900 level, 900, 950 is my expectation for that, Paul.

Okay. And then a final one for me on the longer term; how’s your marketing strategy for money? I mean, now that you have a majority of them so under fixed long-term contract, and then the rest is to the different party in the U.S. and no spot exposure, should we assume that that will essentially be the strategy going forward?

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

Okay, Paul. We have, as you noted, through 2022 to 2024, put in place a number of fixed forward sales related to our Tupper Montney project. So 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 put in place some fixed forward sales to generate free cash flow from the asset while growing. If you look beyond 2024, we are very unlikely to put in place fixed forward sales 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’ll likely feature in our program going beyond 2025. 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 of the U.S. for LNG. So we’ll evaluate those and have sort of a diverse strategy that maximizes our free cash flows.

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

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 if we can find the best outcome, the best deal.

Okay. Thank you.

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

Good morning, Neil.

Yes. Thanks. So 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 2024, but could I imagine there are some moving pieces that you want us as an investment community to get our heads around as it relates to production? So just how should we – any early thoughts and guidance you can provide on 2024 and at an asset level would be great.

Well, thank you, Neil, for that question. Our long-range plan is not even Memorial Day; I try to gauge questions on holidays to see just finished Easter here. So I would say, as 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 offshore. We do have success today at Longclaw. That will take the place of some of our backlog when we want to do that. So I would say it’s a similar year to next year with higher production because we’ll have all of our new backlog wells online; Dalmatian this year, Marmalard next year; and I’d assume it will be a year similar to this with higher production, higher oil production, and higher overall production.

And then that - thanks Roger for indulging it there. And then the follow-up has been a lot of talk about offshore cost inflation. We’re seeing some early signs, hopefully, of 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 any green shoots when it comes to the inflationary pressures?

Yes, thanks, Neil. We've been preparing and I'm going to let Eric speak to you about that this morning.

Okay, thanks, Neil. The big driver for our cost for offshore is really rig rate, and we're sort of advantage this year, and we're really happy with how we're set up for 2024 into 2025. So for about half of our program offshore in 2023, we have 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 2023, 2024, and the first part of 2025 at what is effectively market rate right now, which is around $430,000 a day for drillships. 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 2025. We’re really happy with that.

Good stuff, guys. Thank you.

Thank you, Neil. Appreciate it.

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

Good morning, Charles.

Good morning, Roger. I wanted to ask a question about these Karnes refracs. So it’s really intriguing to me that you had higher IPs than the initial completion. But I wonder if you could add a few more coordinates to that. I’m thinking, what was the – what's the decline profile look like 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 2023.

Thank you, Charles. Eric's got it; he came up with this plan. I'm going to let him tell you about it.

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. We looked at wells that were initially fractured with less than 1,200 pounds per foot of profit. If you compare that to our current completion design of 2,800 to 3,400 pounds per foot, they look quite a bit understimulated. 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 helps improve the performance of our new wells. We’re getting nice production uplift and reserve recovery from those refracs. They're pretty exciting; we're seeing rates go from 15 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 4-inch casing. We go in perf and frac, kind of like a new well, just a little bit skinnier hole. We’ve had great success with it, and we’re really excited. We're 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 we're looking at. Hope that helps you give a little background on what we're trying to do there.

That's a lot of great detail. Thank you, Eric. And my second follow-up question, Roger, is about the King’s Quay facility. I went back and looked, and I guess the nameplate capacity was more like 102 MBOE a day. It seems you guys are producing something north of 20% over that with this rate that you disclosed today. So what should we expect going forward? It seems that you're kind of knocking up against the ceiling of what that facility could do. 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.

Thank you, Charles, for asking that question. It's a big home run feel for us, one of the greatest in company history for us. It's going to be very difficult to produce more than that headline we had today. Our equipment's running at the maximum. Let's keep in mind that when we purchased this project and executed it through COVID, there was another field in the Gulf called Delta House, a very similar facility that has multiple fields flowing into it that we also operate. That field has also been able to exceed nameplate capacity, and our team was able to learn from that experience as we operate King’s Quay and take this over nameplate. We're probably not going to see production levels much higher than that, but we're very happy about where we are. I also have to keep in mind that Samurai is a field that's a 50% working interest for us. When Samurai does well, we do well. The field's doing well and is going to be on a plateau here into 2025, and it's going to be some additional things that we're finding to do in the area. Samurai gets better and bigger every day. So, it’s a big home run ball; we probably can't make much more production than that, but that's a lot of production coming out of eight wells. We’re really proud of it. Thanks for noting that.

Thank you for the detail, Roger.

You said – thought you wanted more detail, Charles. I'd say, wow.

Another time. Another time.

Appreciate you calling in.

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

Good morning, Leo. Thanks for calling in.

Yes, 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 of net pay, which I know is not the only metric but 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? It 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. What’s the risk profile on this thing? This is a true exploration well, kind of a one in five type well in terms of the expectation. Any color on that would be great.

Thanks for that question, Leo. Absolutely. When we say well discovery, we anticipate producing that well and increasing our working interest on it. The issue is the size of it, not that we’re working it. I’d say it’s a 10 million 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 and pipes already in place. So the economics of this are similar to Samurai, which is incredible; this well will have incredible economics. Also, as we operate other fields and operate King’s Quay, a new set of wells not involved with the original field will lower the operating expenses across the whole platform for us. This is very positive for us. It's not a massive oil field, but we can make a lot of money and do well here and work with our partners. We were carried in the well a little bit, and we’re hoping to do that in other places because we have – we are a top executing company in the Gulf. As for 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 number seven, if you will. I would say it’s a little better than one in five exploration well. It is in a totally undrilled fault block. A lot of these major Wilcox fields, such as St. Malo and also here at Cascade, Chinook and many others in the Gulf, have two big features to them with a large fault down the middle of the field. This so happens to have not been tested. We looked at this and compared it to other wells that have been drilled on both sides of major faults through these facilities, I mean, through these types of plays. We have a big nice well to drill here; it can make this project last until 2040. The FPSO there is a very highly operated efficient FPSO. We can move the crude off that FPSO where we need to on the Gulf Coast with tankers, so it comes with positive differentials and many positive things for us. It’s in a – it’s near the field, but in a totally untested fault block. We’re very happy about drilling this well and have a chance to, again, add more to our backlog. The well could get very large in size requiring multiple wells if successful or could be a simple tieback, so we’re real happy about it, and thank you for asking us about it.

All right, that’s helpful. And then just on the sort of free cash flow uses here in the second half, it sounds like you’re focused on paying down debt. I imagine that there’s probably going to be some takeouts of some of these existing bonds, kind of like you’ve done in the past with some tenders here. But just in light of lower oil prices, does this make the share buyback kind of fairly unlikely here in 2023 with the focus on debt reduction? Do we need oil prices to go up before maybe your buyback shares? I mean, just kind of talk about the dynamic between those two.

I’ll let Tom add all the color, but our framework as we set up has a portion for buyback or advanced returns, which will soon be buyback with debt reduction. We can end up with less if oil prices are lower, but there’s 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 Tom give you some more information on that.

Yes, 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. With this pullback in oil prices, maybe the quantums will be a little smaller than what we would’ve planned at $75 WTI, but that still is what we’re planning to do following our framework 75-25 between debt reduction and share purchase.

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 the high level sort of cadence here? Do we see Gulf of Mexico volumes in the third quarter 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 the fourth quarter? I imagine that onshore, you’re going to see the nice ramp in the third quarter as you get the benefit of more wells coming online. Just got any help on production cadence in the third quarter and fourth quarter, just kind of the big moving pieces here.

If you look at our guidance today for the second quarter, we're making a little bit less in the Gulf of Mexico; 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. 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. I’d say it’s – right now we’ve guided 80 to 81 here in the second quarter, probably trying to get close to 83 in the third, and a little higher; possibly in maybe 90, a little more than 90 in the fourth quarter there, Leo.

Yes, Leo, just a bit of background; I think we’ve noted before that our onshore program is pretty heavily weighted with some 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.

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

Appreciate it. Take care.

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

Hey guys.

Good morning, Paul.

Yes, 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 well in the Eagle Ford, right?

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

All right, thank you. And Roger, just curious; in the Longclaw you only have 10% interest, and you are the operator, which is quite unusual for someone with a small percentage like that to be the operator. Is there any game plan there for you to boost the interest or is this – I’m just curious about why you would take the operatorship there.

Thank you, Paul. You can operate things at 10% when you’re real good, and we’re real good, so that’s kind of how that goes. This was a long-term prospect known when we purchased the field Khaleesi, Mormont, and we had our significant discovery at Samurai right next door. Several of the partners in the field owned this opportunity, and they came to us to participate in the well. If you notice in my commentary, we have an ability to increase our working interest post the well being cased, which we’re going to do. This well is – this team that built this prospect really respects our company as an operator. We also have work going on in the middle of our most valuable field we've ever owned, probably. We want to operate and ensure operations out in the middle of King’s Quay and Samurai. This is located 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. 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 and safely, and increase our working interest due to our operating skill and then lower the operating expenses of the facility. So it’s a win across the board for us, and we have a great relationship with these partners as they see us as a good operator, and we execute the well farm at a low working interest and everybody wins today, Paul.

All right, thank you.

Thank you.

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

I appreciate everyone dialing in today. I appreciate the questions from our key analysts today. It was good commentary back and forth, and I really appreciate that support. 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.

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