Murphy Oil Q1 2023 Earnings Call Transcript

Quartr
Provided by Quartr
May 3, 2023

There are 11 speakers on the call.

Operator

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corp. 1st 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.

Speaker 1

Thank you, Joelle. Good morning, everyone, and thank you for joining us on our Q1 earnings call today. Joining me today is Roger Mr. Jenkins, President and Chief Executive Officer along with Tom Morales, Executive Vice President and Chief Financial Officer and Eric Hambly, Executive Vice President Please refer to the informational slides we placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude non controlling interest in the Gulf of Mexico.

Speaker 1

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 discussion of risk factors, see Murphy's 2022 Annual Report on Form 10 ks on file with the SEC.

Speaker 1

Murphy takes no duty to publicly update or revise any forward looking statements. I will now turn the call over to Roger.

Speaker 2

Thank you, Kelly. Good morning, everyone, and thanks for listening to our call today. On Slide 2, Murphy continues to deliver strong value proposition to our shareholders, Our ongoing execution excellence across our significant offshore backlog and over 1,000 oil weighted onshore locations we'll 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, Marmont, Samurai fields in the Gulf of Mexico.

Speaker 2

Murphy also has an ongoing exploration portfolio As we're in process of a 3 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 $500,000,000 debt reduction goal for 2023 as we execute Murphy 2.0 of our capital allocation framework. Recognition of our debt reduction efforts over the past 2 years, along with our great execution success, especially in the Gulf of Mexico, We recently received a credit rating upgrade to BB Positive with a stable outlook from S&P Global. Our efforts to on maintaining strong well performance and uptime led to Murphy's Q1 production volumes of 172,500 barrels equivalent per day, Exceeding the upper end of our guidance, we executed our onshore well program as planned with 15 operated wells online.

Speaker 2

In the Gulf of Mexico, our team brought online the Samurai 5 well, attended 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 1 year anniversary of achieving first oil at Kings Key. I'm pleased to say that the gross cumulative production on that facility in the 1st year was more than 30,000,000 barrels equivalent. On the exploration front, we disclosed today the success at the Longclaw well, and we're awaiting results of 2 additional exploration wells Later this year, we also added to our exploration portfolio with 6 blocks from the recent Gulf of Mexico Federal sale. As we continue to support our shareholders through targeted terms, Murphy announced last month to be maintaining our quarterly dividend at with $0.275 per share or $1.10 on an annualized basis, which we note is the highest rate since 2016.

Speaker 2

On Slide 4, exceeding guidance for the Q1 across all of our assets due to stronger well performance, Production of 172,500 equivalent per day consists of 94,000 barrels of oil per day, Which represents a 25% oil growth since the Q1 of 2022, our highest Q1 production level since 2020. In the Gulf of Mexico, we produced nearly 4,000 barrels equivalent per day above our guidance as well as 1100 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 I'm now going to turn the call over to our CFO, Tom Morales, for an update on our financials and sustainability efforts. Tom?

Speaker 3

Thank you, Roger. Good morning, everyone. Slide 5. Our first quarter net income totaled $192,000,000 or $1.22 per diluted share. Including after tax adjustments, Adjusted net income was $195,000,000 or $1.24 per diluted share.

Speaker 3

Our continued operational generate strong cash from operations including non controlling interest of $280,000,000 which also reflects $124,000,000 of our contingent After accounting for net property additions, we had negative adjusted cash flow of $66,000,000 Which is a reflection of our forecasted capital program being heavily weighted to the Q1. The remaining $48,000,000 of our Q1 contingent consideration payments We're reflected in the financing activities section of the cash flow statement. These contingent consideration payments Related to 2 Gulf of Mexico acquisitions in 2018 2019 and were structured as revenue sharing payments once certain thresholds were exceeded. The last revenue sharing contingent payments were made in the Q1 as reflected in our financial statements. A final $25,000,000 payment was made in April related to the 1 year anniversary of first oil at Kings Key, which fulfills all of Murphy's obligations on these transactions.

Speaker 3

Slide 6. We maintained a high level of liquidity in the Q1 of $1,100,000,000 Consisting of our $800,000,000 credit facility and more than $300,000,000 of cash and equivalents. I'm pleased that Murphy recently received a credit rating upgrade to BB Plus 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 $500,000,000 debt reduction goal for 2023. Slide 7.

Speaker 3

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 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 2nd consecutive year. With that, I will turn the call over to Eric, our Executive Vice President of Operations to discuss our asset success.

Speaker 4

Thank you, Tom, and good morning, everyone. Slide 9. Murphy's Q1 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 2 successful refracs. Additionally, We had 7 gross non op wells come online in the quarter across our Tilden and Catarina acreage.

Speaker 4

For the 2nd quarter, we plan to bring online 9 Over the past few years, our Karnes program has included a couple 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 Shale performance. Our average 250 day QM per foot demonstrates the improvement we've seen with our enhanced completion design, Which we've highlighted in previous quarters. Slide 10.

Speaker 4

In the Tupper Montney, Murphy produced 292,000,000 cubic feet per day In the Q1 and brought 5 wells online as planned. Our well delivery program continues in the Q2 with 3 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 Q1 2023, we sold approximately 17% of our volumes at Malin, Chicago, Ventura and Dawn pricing

Speaker 2

For an average US6.65

Speaker 4

dollars per 1,000 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 US2.59 dollars per 1,000 Cubic Feet for the Q1, 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.

Speaker 4

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 1 year of achieving first oil at Kings Key and note the significant accomplishment of more than 30,000,000 barrels of oil equivalent gross cumulative production in the 1st 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 percent uptime. Our operating partner at Terra Nova continues to work on maintenance and commissioning activities in Newfoundland, And Murphy maintains the view that it will be back online at year end. And with that, I will turn it back to Roger.

Speaker 2

Thank you, Eric. On Slide 14, we're pleased to announce we have today that Murphy's operator drilled a discovery at the Long Claw Exploration Well Green Canyon 433 in the Gulf of Mexico, this well will be a tieback to our Kings Key facility. We found 62 feet of net oil pay and are evaluating results well just finished here just recently. Murphy held a 10% working interest While drilling long haul and received a 4.5% carry after casing. So after our election, we will hold 14.5% working interest in this well.

Speaker 2

As previously disclosed, Murphy temporarily suspended drilling on the Oso No. 1 exploration well at 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 Q3 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 3rd well, Chinook 7, which is located in Walker Ridge 425. We spud this well just 2 days ago. We anticipate the cost of $48,000,000 net to Murphy.

Speaker 2

We estimate a mean to upwards gross resource potential of 50,000,000 to 120,000,000 barrels equivalent from this well, if successful, we intend to tie this well And to 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 $875,000,000 to $1,025,000,000 We also reaffirm our full year 2023 production range of 175,000 to 183.5 1,000 barrels equivalent per day, which is 55% oil. Overall, this achieves a 10% oil growth From full year 2022 and 7 percent total production growth. For the Q2, we forecast an estimated production range of of 173,000 to 181,000 barrels equivalent per day with approximately 54% oil 60% liquid volumes. Our forecast accrued CapEx for the quarter will be $320,000,000 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 $1,000,000,000 we maintain a broad a Board rather Authorize initial 300,000,000 share repurchase program, allowing Murphy to repurchase shares through a variety of methods with no time limit.

Speaker 2

As of today, we have not executed any repurchases under that authorization. On Slide 18, we continued our disciplined strategy to delever, Execute, explore and return. And our near term plan is to reduce debt by $500,000,000 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 $900,000,000 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 to 100,000 barrels equivalent per day in that period.

Speaker 2

Overall, we continue to utilize excess cash flow as we execute our plan of enhancing payout 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 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 will have ample free cash flow generated from this plan to fund further debt reductions On Slide 19, on strategic priorities, looking forward for the remainder of 'twenty three, 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 supported by our multi decade sustainable onshore business. We also have 2 additional key exploration wells to drill this year.

Speaker 2

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. I'll now turn the call over to everyone for their questions. Thank you.

Operator

Thank you. Ladies and gentlemen, Your first question comes from Arun Jayaram with JPMorgan. Please go ahead.

Speaker 5

Good morning, Roger.

Speaker 2

Good morning, Marilyn.

Speaker 6

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.

Speaker 2

Yes. Thanks for that question about all that. We had a very good lease sale. We just finished up this long call well, just finished drilling the well not even a week ago or 5 or 6 days ago, which we had success, Oso is a well we'll be returning to in the Q3. We have a plan From our team to execute that well with some additional equipment that we need, I would also comment that Dassault area was quite active in the lease sale.

Speaker 2

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're 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.

Speaker 2

The Chinook well is a well we've been planning for a very long time. This is a significant undrilled fault block near our Cascade Chinook field that we purchased from our Portforma 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 spud that well yesterday And really excited about that well. We do have a backlog of other opportunities that I'll have Eric address involving development here.

Speaker 2

Eric, why don't you update Arun on that?

Speaker 4

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 5 to 7 years, Including 26 projects with 125,000,000 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.

Speaker 2

But with the ongoing activity of Arun, we will be bringing on Dalmatian Well later this year and drilling and hopefully completing a Marmelar well that probably just really can't flow much right at the end of the year.

Speaker 4

Should flow early in the 'twenty four.

Speaker 6

Great. And Roger, I wanted to see if you could give us an update on your plans and Non op and operated plans in Canada, you highlighted 2 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.

Speaker 2

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 a timing rather than an open ended type dialogue. And we are hopeful to work with them more ahead and engage with them and 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, All time, great field for us and have a couple of wells that are planned.

Speaker 2

I will say, as we frame and talk about Terra Nova in your commentary this morning, You noted about the well discussed Terra Nova. We have made $1,200,000,000 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 through a government deal. This is an incredible project. This project will come online.

Speaker 2

This project will have incredible high return. Heibernia too made almost $3,000,000,000 of free cash flow itself. So these are significant successful Long term feels for us and we're well positioned there to make a lot of free cash flow in East Coast Canada.

Speaker 7

Great. Thanks

Speaker 2

a lot. Thank you.

Operator

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

Speaker 8

Good morning, Al. 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 wonder how you would balance, You've got obviously the positive things going on at Kings Kay.

Speaker 8

You've got some interest in exploration. I'm just wondering how you would balance maybe seeing some additional working interest or other opportunities within those 2?

Speaker 2

That's a good question, Arun. 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 long standing inventory of onshore wells along with the framework that I not the capital allocation framework, but our long term plans As 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 will be picking and choosing between our long term projects in the Gulf and our 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 both off and onshore. We got offshore inventory too. And Eric has done a great job at pulling it together.

Speaker 2

And we're going to be executing it like on Slide 12 this year. There will 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 have.

Speaker 8

Great point. And then, Raj, maybe for you or Tom, just second on free cash flow allocation. I believe your debt targets Or on a gross not net basis. So, it 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, about $400,000,000 or so for M and A and discoveries.

Speaker 8

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 1 to 2 quarters of debt reduction in favor of a cash build or how do you sort of see that plan going forward?

Speaker 3

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 debt. As you saw in our financials, we are kind of front loaded here with our capital. So it's probably more of a Activity we'll see in the second half of the year, starting to reduce that debt with any adjusted free cash flow we have.

Speaker 6

I have

Speaker 2

a little bit of color to add to that, Neil. I think it needs to be pointed out. If you look at our cash flow statement, yes, our cash Went down about the same amount of the contingent payments. So we're talking about paying contingent payments into very successful M and A, There was a revenue sharing, which we received the other high. Also, all this M and A is completely paid out, including acquisition, have been paid out.

Speaker 2

Clisi Monmouth has been paid out. Delta House has been paid out. So we have paid out assets. And if we have a severely front loaded capital And without contingent payments 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.

Speaker 8

That's a great point. Thanks, Roger.

Speaker 2

Thank you, Neil. Good to hear.

Operator

Your next question comes from Paul Cheng

Speaker 9

A number of Quick question. Maybe the first one just administrative that the April contingency payment, when it's going to show up in cash flow statement is in the financing activities or just in the cash flow from operation?

Speaker 2

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 $25,000,000 we've already paid it this month. I'm not where is it, Tom? It will be an operating cash flow, I would assume.

Speaker 3

It will also be split a little bit between operating.

Speaker 2

It will be split between financing and operating. That's due to the original setup of the M and A deal in our accounting, Paul. But that's over. After that, this stuff is over, Paul, for all that.

Speaker 9

No, I understand. We're just saying that because I think that the investor will be looking at the CFFO number more closely typically. So we want to know whether that $25,000,000 is going to be in there or it's going to be in the financing activity line? Second one, Voyager that in post-twenty 26, once you get to 200,000, 220,000 barrels per day kind of

Speaker 2

I believe it's disclosed in that slide, Paul. Turn to that, Megan, please. In the 'twenty six, 'twenty seven period, I would anticipate it to be in the similar level that we are on the left hand side of that slide at the 900 level, 9, 950 This is my expectation for that, Paul.

Speaker 9

Okay. And then a final one for me. On the longer term, how's your marketing strategy for Mani? I mean, right now that you have Majority of them sold under fixed long term contract and then the rest is to the different part in the U. S.

Speaker 9

Should we assume that, that will be essentially the strategy going forward?

Speaker 2

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

Speaker 4

Okay, Paul. We have, as you noted, we Through 2022 to 2024, put in place a number of fixed forward sales related to our Tupper Montney project. So As you know, we increased the capacity of our plants there by 200,000,000 cubic feet per day and we've had a multiyear program Of adding a slightly higher level of activity to get those plants full, which we expect probably by the second half of twenty twenty four. In order to support that additional capital allocation to the asset, we put in place some fixed forward sales 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 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.

Speaker 4

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 of the U. S.

Speaker 4

For LNG. So we'll evaluate all of those and have sort of a diverse strategy that maximizes our free cash flows.

Speaker 9

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?

Speaker 4

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

Speaker 9

Okay. Thank you.

Operator

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

Speaker 7

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 24, but I would imagine you Yes, really, really.

Speaker 7

Yes, really, I recognize that, but I would imagine there 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.

Speaker 2

Well, thank you, Neil, for that question. Our long range plan is not even Memorial Day, Neil. I try to gauge questions on holidays. We just finished Easter here. So I would as per our page that we have here, we have an averaging CapEx Shown in our deck here today around $900,000,000 That means that CapEx next year at this time in that plan was a little bit less than this year.

Speaker 2

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 Long Claw that would 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'll have all of our new backlog wells online, Dalmatian this year, Marmelar next year, and I'd assume it will be a year similar to this with our production,

Speaker 7

Thanks, Roger, For indulging it there then. The follow-up, there's 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, still a lot of upward pressure.

Speaker 7

So can you talk about how you're mitigating it? And are you you may be, green shoots when it comes to the inflationary pressures.

Speaker 2

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

Speaker 4

Okay, thanks. Neil, the big driver for our cost Or 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 into 2025. So for about half of our program offshore in 2023, we have a significantly below market rig rate, which We locked in around $300,000 a day. The rest of the program, we have locked in pricing all the way through the end of 'twenty three, 'twenty four and the 1st part of 'twenty five at what is effectively market rate right now, which is around 430,000 a day for drillship. We're pretty happy with that and that should be the main component of something that could be inflationary for us.

Speaker 4

We have it locked in through early 2025. Really happy with that.

Speaker 7

Good stuff guys. Thank you.

Speaker 2

Thank you, Neil. Appreciate it.

Operator

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

Speaker 10

Good morning, Roger. To you, good morning. 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 Then I guess the initial completion, but I wonder if you could add a few more coordinates to that. And I'm thinking what's the Client profile look versus the original decline profile and how maybe the completion design or intensity versus The original completion and whether you plan on doing more of these in 2023.

Speaker 2

Thank you, Charles. Eric's Got it. Came out with this plan, I'm going to let him tell you about it.

Speaker 4

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 We initially fractured with less than £1200 per foot of proppant. If you compare that to our current Completion design of 2,800 to 3,400 pounds per foot, they look quite a bit under stimulated.

Speaker 4

Over the last 3 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, 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 to 20 barrels a day to up to 1500 barrels a day initially.

Speaker 4

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 7 or 8 years ago. So it looks like a good opportunity for us. What we do in those wells is we run a 4 inches casing. We go in perf and frac kind of like a new well, just a little bit skinnier hole.

Speaker 4

And we've had great success with it. We're really excited. We're currently evaluating what might become a standalone program to address that 220 while 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.

Speaker 10

That's a lot of great detail. Thank you, Eric. And my follow-up question, Roger, is I think it's about The Kings Key facility, I went back and looked and I guess the nameplate on that as originally designed was more like 102 MBOE 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?

Speaker 10

It would seem to me that you're kind of knocking up against the 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.

Speaker 2

Thank you, Charles, for asking that question. It's a big home run field 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. Let's 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.

Speaker 2

It's a very Similar facility that has multiple fields flown to that we also operate. And that field also has been able to go over 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. I have to also keep in mind that Samurai is a field that's 50% working interest for us. And when Samrod does well, we do well.

Speaker 2

And the field is 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 and bigger every day. So Big home run ball, probably can't make much more production than that, but that's a lot of production out of 8 wells. So we're really, really proud of it and thanks for noting that.

Speaker 4

Thank you for the detail, Roger.

Speaker 2

You broke up, Charles. I'm sorry.

Speaker 10

No, that was just saying thanks

Speaker 4

for that detail. That's it for me.

Speaker 2

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

Speaker 10

Another time.

Speaker 2

Another time.

Speaker 10

Another time.

Speaker 5

All right.

Speaker 9

I appreciate

Speaker 2

your call, man.

Operator

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

Speaker 2

Good morning, Leo. Thanks for calling that.

Speaker 5

Yes, good morning. I was hoping to get a little bit more color around the exploration program here in the Gulf. Just on the Long Claw 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 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.

Speaker 5

And then just on the Chinook well, I 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 this a true exploration well, kind of 15 type well in terms of the expectation? Just any color on that would be great.

Speaker 2

Thanks for that question, Leo. No, absolutely. When we say a well is a discovery, 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 is we're working it. I'd say it's a 10,000,000 to 20,000,000 barrel discovery.

Speaker 2

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 an incredible economic and also as we operate other fields and operate Kings Key, A new set of well 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 that 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.

Speaker 2

We're a top executing company, Leo in the Gulf. On to 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 7, if you will. I would say it's a little better than a 1 in 5 exploration well.

Speaker 2

It isn't 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 2 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 Other wells have been drilled on both sides of major faults through these facilities, I mean through these type plays And we have a big nice well to drill here.

Speaker 2

It can make this project last out to 2,040. 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 with positive differentials And 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, Require multiple wells is successful or could be a simple tieback.

Speaker 2

So, real happy about it and thank you for asking us about it.

Speaker 5

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 very 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 kind of light of sort of lower oil prices here, Does this make the share buyback kind of fairly unlikely here in 2023 with a focus on debt reduction that we need oil prices to kind of go up before maybe you buy back shares, I mean just kind of talk about the dynamic between those 2.

Speaker 2

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 buyback with debt reduction. So 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

Speaker 3

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 Not going to share repurchase. So with this pullback 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, dollars 75.25 Between debt reduction and share repurchase.

Speaker 5

Okay. That's helpful. And then just on your production volumes, obviously, you've got 2nd 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?

Speaker 5

Do we see Gulf of Mexico volumes in 3Q maybe kind of flat to down? So volumes in 3Q maybe kind of flat to down with just hurricanes likely here in terms of the way you guys are or 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 Q3 Q4, just kind of the big moving pieces here?

Speaker 2

Well, if you look at our guidance today for the Q2, making a little bit less in the Gulf of Mexico, we have to shut in Kings Key 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 Q3, while under a big hurricane downtime still is higher than 2nd quarter and a big into the year. So I'd say as right now we've guided $80,000,000 to $81,000,000 here in the second quarter, Probably trying to get close to 83 in the 3rd, a little higher possibly and maybe 90, A little more 90 in the Q4 there, Leo.

Speaker 3

Yes. Leo, just a bit

Speaker 4

of background. 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 see more growth onshore heading into the 3rd quarter And then more growth offshore heading into the Q4 as we bring online Dalmatian, Terra Nova, the Dalmatian new well, DC-ninety well And Terra Nova restart along with less weather downtime assumed in the Q3. So 3rd, 4th quarters aren't that dissimilar from production rate with a little more growth from 2nd quarter onshore in the 3rd quarter and a little more growth offshore in the 4th quarter.

Speaker 5

Okay. Very helpful guys. Thank

Speaker 2

you. Appreciate it. Take care.

Operator

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

Speaker 9

Hey guys.

Speaker 2

Hey guys. Good afternoon,

Speaker 9

Paul. Yes, just want to clarify. Eric, when you're talking about the refrac those opportunities, 220 wells, that's not included in your current 1100 well in the Eagle Ford, right?

Speaker 4

That's correct. Those are wells that are already producing. They're not included in our 1100 wells of remaining Eagle Ford inventory. It would be addition to that.

Speaker 9

Thank you. And that what you're just curious that in long haul, 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 boost the interest or that I mean this interest is I mean I'm just curious about why you would take the operatorship there?

Speaker 2

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 kind of how that goes. This was a long term prospect that was known when we purchased the field, Khaleesi, Moremont and we had our Significant discovery at Samurai Next Door, several of the partners that are in the field owned this opportunity. They came to us to participate in the well.

Speaker 2

And if you notice in my commentary, in my script commentary, We had an ability to increase our working interest post the well being cased, which we're going to do. So we have an ability to go up to 14.5%. This well 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 Kings Key and Samurai.

Speaker 2

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 smaller working interest.

Speaker 2

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 skill and then lower the operating expenses of the facility. So It's a win across the board for us and the partners are a great relationship with these partners and they see us as a good operator and we execute the well farm

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.

Speaker 2

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

Operator

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

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Earnings Conference Call
Murphy Oil Q1 2023
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