Murphy Oil Corporation (MUR) Q4 2022 Earnings Call Transcript

Murphy Oil Corporation (NYSE:MUR) Q4 2022 Earnings Call dated Jan. 26, 2023.

Corporate Participants:

Kelly Whitley — Vice President, Investor Relations and Communications

Roger W. Jenkins — President & Chief Executive Officer

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

Eric M. Hambly — Executive Vice President, Operations

Analysts:

Arun Jayaram — JPMorgan — Analyst

Charles Meade — Johnson Rice — Analyst

Leo Mariani — MKM — Analyst

Paul Cheng — Scotiabank — Analyst

Neal Dingmann — Truist Securities — Analyst

Neil Mehta — Goldman Sachs — Analyst

Geoff Jay — Daniel Energy Partners — Analyst

Presentation:

Operator

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2022 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 and Communications

Good morning, everyone, and thank you for joining us on our fourth quarter earnings call today. Joining me 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 noncontrolling interest in the Gulf of Mexico.

Slide 1, please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that 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 2001 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements.

I will now turn the call over to Roger Jenkins.

Roger W. Jenkins — President & Chief Executive Officer

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

On Slide 2, Murphy continues to deliver a strong value proposition, our ongoing execution accepts, especially in our oil-weighted assets, ensures 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 our Khaleesi, Mormont, Samurai fields in the Gulf of Mexico.

Murphy has an ongoing exploration portfolio, and we’re in the process of a three-well operated program in 2023. We continue to generate strong cash flow and we’ve been able to more than double our long-standing dividend from 2021, all while significantly reducing debt. As a result of this success, we’re progressing our capital allocation framework, where we will support increasing returns to shareholders as various debt targets are reached.

Slide 3. As we continue focusing on our four priorities to delever, execute, explore and return, I’m very pleased at the progress we have made as a company. In 2022, Murphy achieved our $650 million debt reduction goal resulted in a 40% or $1.2 billion reduction since the end of 2020, and our current debt level is $1.8 billion. This has positioned us to begin Murphy 2.0 of our capital allocation framework, where we will allocate 75% of our adjusted free cash flow to debt reduction and 25% of our adjusted free cash flow to shareholder returns beyond our dividend.

Our team has done an incredible job executing our Khaleesi, Mormont, Samurai project, where we initiated production ahead of schedule, and we continue to produce above expectations. Additionally, the King’s Quay facility maintains an industry-leading uptime average of 97%. I’m sure we executed our well delivery program well with 40 operated wells and 15 gross non-op wells during 2022.

We maintained a total reserve base of 697 million barrels of oil equivalent at year-end. We’ve continued our excellent environmental performance with the second consecutive year of no IOGP recordable spills in our business, all while reducing emission intensity. Murphy closed out our 2022 exploration program by spudding the Oso-1 well as operator in the Gulf of Mexico during the fourth quarter and drilling is ongoing today. After this well, we look to spud two more operated exploration wells in the Gulf of Mexico early this year.

On Slide 4. In the fourth quarter, we produced 173.6 MBOEPD at 62% liquids due to the significant impact from our Khaleesi, Mormont, Samurai field development. We achieved nearly 30% growth in our oil volumes to 97,000 per day of oil since the first quarter of 2022. Our realized oil price was $82.57 while our realized NGL price was $27 per barrel and nat gas was $364 per 1,000 cubic feet.

So turning to Slide 5. For the full year, our company produced 167,000 barrels of oil equivalent per day with nearly 90,000 barrels of oil or 54%. This represents a 6% increase in total production from full year ’21. Our accrued capex for the year totaled $1.016 billion, excluding noncontrolling interest, acquisitions and acquisition-related capex. For the year, our realized oil price was slightly above the WTI benchmark at nearly $95 per barrel, while NGL was $36 per barrel and nat gas at $364 per 1,000 for the year.

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

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

Thank you, Roger, and good morning, everyone. Slide 6. Our proved reserves totaled 697 million barrels of oil equivalent at year-end 2022, reflecting a 98% total reserve replacement effectively remaining flat from year-end 2021 proved reserves of 699 million barrels of oil billings. With average annual capex of approximately $880 million, excluding noncontrolling interest and including acquisitions, Murphy has been able to maintain its proved reserves at around the same level since 2020. Compared to the prior year, Murphy increased its proved developed reserves to 60% from 58% of total proved, while our liquids weighting improved to 47% from 45%. Overall, across our entire portfolio, we preserved our reserve life at an average of more than 11 years.

Slide 7. We closed out the year with outstanding financial results as our fourth quarter 2022 net income totaled $199 million or $1.26 per diluted share and the full year 2022 net income was $965 million or $6.13 per diluted share, which is the highest Murphy has had since 2019 and second highest in the last 10 years. Including certain after-tax adjustments, we reported adjusted net income of $173 million or $1.10 per diluted share for fourth quarter 2022.

With advantaged oil price realizations, we generated significant cash from operations, including noncontrolling interest for the quarter and full year. After accounting for net property additions and acquisitions, we achieved positive adjusted cash flow of $321 million and $1.07 billion for the fourth quarter 2022 and full year 2022, respectively.

Now that 2022 has ended, I’m pleased to say that through our continued capital discipline, we generate sufficient cash flow to fund capex, require higher returning working interest in Gulf of Mexico properties, double our dividend and reduce debt by $650 million.

Slide 8. As of December 31, 2022, Murphy had $492 million of cash and equivalents on hand, resulting in net debt of just $1.3 billion. Additionally, in November, we entered into a new $800 million senior unsecured credit facility maturing in November 2027, which was undrawn at year-end 2022.

Slide 9. In conjunction with our focus on operational execution, we continue to reduce our impact on the environment through lower greenhouse gas emissions intensity. In 2022, the team reduced our emissions intensity by 5%, and we recorded lower flared volumes onshore, both to the lowest level on company record. I’m proud to say that we have now achieved 2 consecutive years of zero IOGP spills. We also recorded our highest water recycling ratio in company history with 3 million barrels of water recycled representing 28% of our total onshore water use, which is up from 18% in 2021.

With that, I will turn it over to Eric Hambly, 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 11. Our Eagle Ford Shale wells produced an average 32,000 barrels of oil equivalent per day in the fourth quarter with 85% liquids. For the year, production was slightly above at 34,000 barrels of oil equivalent per day as we brought 27 operated wells and 15 gross non-operated wells online. We carried our new completions design through our well program in 2022, which achieved results above expectations, including some of the highest per foot IP30 rates in Murphy’s history. Overall, in 2022, Murphy achieved industry-leading well results, which was validated in a recent sell-side report on the Eagle Ford Shale. Our team also worked to improve our downtime, which achieved a company record low of 2.8%. Additionally, our base production management efforts continue with base declines averaging 12% for wells online prior to 2022.

Slide 12. Our Tupper Montney business produced 288 million cubic feet per day for the fourth quarter, which included a 17% royalty rate for the quarter, as anticipated. For full year 2022, we produced an average 296 million cubic feet per day and brought online 20 wells during the year. While the majority of our production is protected with fixed price forward sales contracts, we also employ a price diversification strategy for a portion of our volumes. For fourth quarter 2022, we sold approximately 18% of our volumes at Malin, Chicago, Ventura and Dawn pricing with the remaining 17 million cubic feet per day exposed to AECO prices.

Slide 13. In the Kaybob Duvernay, Murphy produced 5,000 barrels of oil equivalent per day for the fourth quarter with 72% liquids weighting. For full year 2022, we produced 6,000 barrels of oil equivalent per day with 74% liquids and brought on line three operated wells.

Slide 15. Our Gulf of Mexico assets produced 84,000 barrels of oil equivalent per day in the fourth quarter with 81% oil volumes. For 2022, we produced 72,000 barrels of oil equivalent per day and maintained 80% oil weighting. Our Gulf of Mexico production was up 10% for the year. I’m pleased that the progress made with our short-term tieback projects during the year as we drilled a successful well at Dalmatian, which is scheduled to come online in 2023. Additionally, two non-operated Lucius wells were brought online in the fourth quarter of 2022 and the first quarter of 2023, while the non-operating St. Malo waterflood project is progressing towards completion in early 2024.

Slide 16. I’m tremendously pleased with the success of the Khaleesi, Mormont, Samurai development project and the Murphy-operated King’s Quay floating production system as production continues to exceed expectations. We recently drilled a successful well at Samurai 5 after previously discovering additional pay zones in the Samurai field during the initial phase of development and the well is scheduled to come online in the second quarter of 2023.

We forecast production to plateau across the three fields for the next several years without additional development. I’m also excited to say that we are forecasting full cycle payout in the second quarter of 2023 for Khaleesi and Mormont, which is approximately five years ahead of our original sanction case.

Slide 18. During the fourth quarter, we spud the Oso exploration well in the Gulf of Mexico and drilling is ongoing. We anticipate that we will reach TD in March. We estimate a mean to upward gross resource potential of 155 million to 320 million barrels of oil equivalent from Oso, which is forecast to cost approximately $26 million net to Murphy.

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

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Eric. On Slide 20. Our 2023 capital plan has a range of spending of $875 million to $1.025 billion. More than two-thirds of our spending is scheduled to occur in the first half of the year, with approximately 70% of our development capital going towards operated projects. Overall, this front-end loading of our spending ultimately generates more free cash flow over the year. I’m excited to say that our cash flow supports our 10% increase in our quarterly dividend that was announced today and allows us to set a $500 million debt reduction goal for 2023 using $75 WTI oil pricing, all with a low reinvestment rate of only 45% of our operating cash flow.

Onto Slide 21. Our first quarter ’23 production guidance of 161,000 to 169,000 equivalents per day includes approximately 92,000 barrels of oil or 56%, with 62% of our volumes being liquids. Additionally, this range includes planned downtime of just over 7,000 barrels equivalent per day across all of our assets. I’d like to note that while this production range is lower in the fourth quarter, it reflects our natural production decline due to the first tax weighted capex that we use yearly as we haven’t brought on and operated well in our Eagle Ford jail since September and in the Tupper Montney since July. For the full year ’23, forecast production range of 175,500 to 183,500 barrels equivalent per day with 99,000 barrels of oil per day or 55%. Overall, with lower forecast capex for ’23, this guidance represents a 10% oil growth for the year and a 7% in total production growth.

Moving now to Slide 22. Our total onshore budget for ’23 is $455 million, which we forecast will generate an average production of 90,000 equivalents per day with 35% liquids. In our Eagle Ford Shale business, we plan to spend $325 million to bring online 35 operated and 17 gross non-operated wells with the majority coming online in the second and third quarter.

As part of our well delivery plan, we look forward to taking the learnings from our adjusted completions design and apply it to our new Tilden wells. For 2023, we forecast production of 32,000 barrels equivalent per day with 72% oil volumes or 86% liquid volumes. And our Tupper Montney asset or ’23 plans $125 million, is forecasting to bring online 16 operated wells and produce approximately 313 million cubic feet per day, assuming a C $4 per 1,000 AECO price for the year, we forecast that to equal a 14% royalty rate for 2023. For our Kaybob Duvernay asset, we plan to spend $5 million on field development and estimate production of approximately 5,000 equivalents per day, 57% oil and 69% liquids in that asset.

Turning to our offshore business on Slide 23. Our plan here calls for $365 million budget, which is forecast to generate 89,000 barrels equivalent oil per day, representing a 20% increase from full year 2022. In the Gulf of Mexico, we’re planning to spend $335 million on operated subsea tieback wells at Samurai, Dalmatian and Marmalard as well as two non-operated Lucius wells and a non-operated development in the St. Malo field.

The non-operated St. Malo waterflood project continues to plan. We’ll be progressing this year. For full year ’23, we estimate production will be 82,000 equivalents per day in the offshore business in the Gulf with 79% oil volumes and 72,000 equivalents per day in 2022 was produced. We plan to spend $30 million for our non-operated offshore Canada assets in 2023 to generate production of approximately 7,000 barrels of oil equivalent per day. Plans include development drilling in Hibernia and field development work at Terra Nova and there are plans of returning to production in the second quarter of 2023.

For our exploration plans on Slide 24, the plan calls for $100 million to be spent to target nearly 200 million barrels equivalent, mean, mean unrisked resources in the Gulf of Mexico. As previously mentioned, we are currently drilling the operated Oso well, which was spud in the fourth quarter of ’22. Next, we plan to spud the operated Longclaw well late in the first quarter before moving to a spud of a third operating Gulf of Mexico well towards the middle of ’23. We’re still working a third well location with our partner group at this time.

On Slide 26, this is a reminder slide of our previously disclosed capital allocation framework, which is a multi-tier capital framework that allows for additional shareholder returns beyond the quarterly base dividend while advancing toward a long-term debt target of $1 billion. We’re pleased by achieving into Murphy 2.0 at this time, allowing us to allocate 25% of our adjusted free cash flow towards shareholders. We maintain a Board authorized initial $300 million share repurchase program along Murphy repurchased shares to a variety of methods with no time limit. As of today, we’ve not executed any repurchases under this authorization.

As we move to Slide 27, we continued our disciplined strategy to delever, execute, explore and return. Our near-term plan for ’23 through ’25 is to reduce — is to follow our capital allocation framework with approximately 40% of our operating cash flow reinvested through 2025 with an average $900 million annual capex. We forecast that this will maintain an average of 55% oil weighting in our business and have 195,000 equivalents per day of average production, representing a combined annual growth rate of 8% through 2025 while also supporting our targeted exploration program. Additionally, we plan to maintain offshore production at an average of 90,000 to 100,000 barrels equivalent per day in this period with excess cash flow. We will continue to execute our plan of enhancing payouts to shareholders through dividend increases and share buybacks as laid out in our capital allocation framework.

Longer term in ’26 and ’27, we see Murphy maintaining a sustainable business and targeting investment-grade metrics and we forecast average annual production of approximately 210,000 barrels equivalent per day with 53% oil weighting. Further, our ongoing reinvestment of approximately 40% of operating cash flow forecast ample free cash flow to fund additional debt reductions in our capital allocation framework and enhance shareholder returns as well as fund high-returning investment opportunities.

On Slide 28, to support our long-term sustainability, Murphy maintains a sizable North American onshore portfolio with more than 2,800 total locations across the 3 producing areas as of year-end ’22. And this multi-basin approach provides ample optionality in various price environments. In the oil-weighted Eagle Ford Shale and Kaybob assets, Murphy maintains more than 20 years of inventory with a breakeven price of $40 per barrel or less. The Eagle Ford Shale stand alone with approximately 12 years of inventory are 360 wells with a breakeven of $40 per barrel or less. Assuming an annual 30 well delivery program across these two basins, we hold more than 60 years of inventory in Murphy Oil today.

In Tupper Montney, Murphy holds more than 50 years of inventory, assuming a 20-well program. Overall, we have more than 200 Montney locations with a breakeven price of less than USD1.45 per 1,000 cubic feet.

Our offshore development opportunities on Slide 29. Our very successful offshore business will also be maintained at an average of 90,000 to 100,000 barrels equivalent per day with an average annual capex of approximately $325 million a year through 2027. This plan is supported by a multitude of offshore inventory with 26 projects combined of 125 million barrels equivalent in total resources at a breakeven oil price of $35 or less. And additional five projects representing $45 million equivalent have a breakeven price of $35 to $50.

Progressing our priorities on Slide 30. Today, we outlined our 2023 program and operating plan as well as moving us along in the Murphy 2.0 and allow us to share 25% of our adjusted free cash flow with our investors. Further, we’ve continued to delever with a debt reduction goal of $500 million in ’23 at $75 WTI. Our three producing areas maintain a strong base for the company, and the Gulf of Mexico will have a full year of production at Khaleesi, Mormont, Samurai, flowing to King’s Quay, which will further be supported by production from our successful Samurai 5 well recently drilled. Also in ’23, we’ll be completing a previously drilled well at Dalmatian in addition to a new development well at Marmalard and offshore Canada will be bringing on substantial production at the non-operated Terra Nova field in the second quarter.

With solid year plan in our North America onshore assets, we’re drilling more of our award-winning Eagle Ford Shale locations as well as rebound well activity in the Tupper Montney, now that permitting delays are behind us. Lastly, we’re drilling three operated exploration wells in the Gulf.

As for the future, we are on strong onshore locations with thousands of high-quality low-breakeven wells remain to be drilled in support of our steady long-term production as well as sustainable long-term offshore business and ongoing cash returns to shareholders. Murphy remains a long-term stable company with low investments rates, slight production growth and a growing offshore competitive advantage. And coupled with our keen eye on protecting the environment, we are positioned for long-term success.

In close, I’d like to thank all our dedicated employees for the solid year we had in accomplishing our key priorities, led by oil-weighted assets in the Gulf and Eagle Ford Shale. We had a great year and look forward to what we’ve been able to accomplish in 2023.

With that, we’ll turn it back over to operator and look forward to taking your questions today. Thank you.

Questions and Answers:

Operator

Thank you. [Operator Instructions] Your first question comes from Arun Jayaram with JPMorgan. Please go ahead.

Roger W. Jenkins — President & Chief Executive Officer

Good morning, everyone. Arun, you hear me?

Operator

One moment, please.

Arun Jayaram — JPMorgan — Analyst

Sorry about that. Roger, I want to start with Slide 21. You highlight your expected exit rate for ’23. So 12% oil growth, 14% BOEs that will put you, call it, in the upper 180s for BOEs and I think 103 for oil. I was wondering if you could help us think about kind of the trajectory from 1Q. In particular, I wanted to get your thoughts on what kind of uplift do you expect from the Terra Nova project. And then you did highlight just over 7,000 BOEs a day of downtime. How do you expect that downtime to play into the volumes? And then maybe you could just maybe follow with the — an update on the St. Malo project in early ’24?

Roger W. Jenkins — President & Chief Executive Officer

Is a mixture of me and Eric handling that for you, Arun. Thank you for that question by production. From a 50,000-foot level, I was looking at it early this morning, it’s quite common for us over ’21, ’22 and now ’23 to have a lower production in the first quarter due to our front-end loaded capex where we start drilling like today, we have four drilling rigs in North America drilling and only one frac crew and we’re not a company that carries a lot of DUCs on our books. So we’re looking at pretty significant growth throughout the year. We’re looking going to the mid-170s into the high 180s to finish out the year. But we really have much more oil production than we’ve had in the past.

I’ll get into the downtime, I have Eric handle that in a minute. We have Terra Nova coming on. We have to estimate what we feel turnover will be, and we have that in the second quarter. That will probably be 4,000 to 5,000 our way, minimum there. We’re looking at that whole business being around 7,000 for the year, and that’s what that trajectory is.

And I’ll just let Eric address the downtime issues we have this quarter. We’ll wrap back up and make sure I handle all of your questions.

Eric M. Hambly — Executive Vice President, Operations

Okay. Thanks, Roger. We did highlight in our release that we have some planned downtime in the first quarter, both operated and non-operated Gulf of Mexico for maintenance projects and also in onshore, as we begin our fracture stimulation program, we have some planned shut-ins related to offset frac impact. Those are sort of typical for our business. For the rest of the year, from a downtime perspective, we do forecast a number of planned downtimes in our Gulf of Mexico business, ongoing offset frac impact through the second quarter in onshore and also a provision for a storm downtime, which is typical for us. For the full year, our storm downtime is on the order of 2,200 barrels per day, which is calculated by assuming that from July to October we have a total of eight days of zero production from the Gulf of Mexico.

Just a few more points in terms of production growth. For our onshore offshore business, rather, we have some new volumes coming online from Samurai 5, which we expect in the second quarter, Dalmatian DC 90 well in the second half of the year, and of course, Terra Nova, which you highlighted. So if you think about rough production rates, Samurai 5 is in the 3,000 to 4,000 net BOE range when it comes online. Dalmatian around 5,000 barrels per day and Terra Nova should get to about 6,000 barrels per day net to us when it comes online. And that’s really how we come up with our offshore forecast.

As Roger highlighted, for onshore, with our new volumes, we have quite a bit of growth of Tupper Montney volume from first to fourth quarter with our wells coming online through the year and being fully online in the third quarter. About to see a pretty substantial increase there, and that’s how we — to model our business.

Roger W. Jenkins — President & Chief Executive Officer

Further to that, I think there was a question you had Arun, and I appreciate these questions because we really have a big growth year. We’re proud of our oil growth and ever-increasing oil production.

St. Malo is a great field, one of the best probably margin field in the world. We’re very fortunate to be an owner that. It’s a solid 10,000, 11,000, 12,000 barrels a day business. The waterflood project does come and go with capex. We’re working with a super major here who changes the phasing of the capex on occasion. But this is going to be really about stopping decline and maintaining pressure in the reservoir as we start injecting this in about a year, and there’ll be an inflection from that to add significant reserves there for us. So that project continues to go well. But they face capex in and out on the year on occasion as they execute it, and there’s a production well that’s coming on at the end of this year and also the injector wells are being completed. So Chevron continues to progress that, have a great relationship with them and moving that forward. It’s a very nice asset for us.

Arun Jayaram — JPMorgan — Analyst

Great. And just my follow-up, Roger, is on Murphy 2.0, I think you mentioned you’re soon to reach that $1.8 billion threshold. So how should we think about kind of cash returns in ’23? I mean I was thinking out loud is it just basically we take your free cash flow forecast and multiply it by $0.25, and that will be the cash return to the higher dividend and buybacks. Is that the way to think about it this year?

Roger W. Jenkins — President & Chief Executive Officer

Arun, thanks for that and proud of that framework. That’s not how it works. We have adjusted free cash flow that we described in the slide, and we would be removing from our — so we take the capex or take the operating cash flow less the capital spending on the cash flow statement, then you have to remove dividends and where we have to pay contingent payments. You remember the focus on contingent payments last year. So we’d be removing our NCI payments, our quarterly dividend and our — not NCI, our distributions to pension, abandonments, quarterly dividends and things of that nature, we get to adjusted free cash flow. This is outlined on Slide 26.

This year, we probably have 200 and something, the high 200s of abandonment and contingent payments are the biggest factors in that. Of course, our dividend is well calculatable at around $170 million. So it would have to be pulled out and we’ll share 25% of the rest. And it’s as per the formula every quarter and trying to get to executing it as fast as we can.

Arun Jayaram — JPMorgan — Analyst

Great. Thanks a lot, Roger. Appreciate it.

Roger W. Jenkins — President & Chief Executive Officer

Oh, thank you. Appreciate you.

Operator

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

Roger W. Jenkins — President & Chief Executive Officer

Good morning, Charles.

Charles Meade — Johnson Rice — Analyst

Good morning, Roger, to you and your whole team there. I have a lot of questions I’d like to ask, but I’ll just start with — well, I’ll just do the two. One and a follow up. But the first is on the Tupper Montney. Two things I’m wondering about there. One, you guys cited that well performance up there as one of the reasons that you’re towards the low end of your production guidance on the quarter. And so my question is, was that kind of a onetime thing, something you just saw in 4Q? Or is that something that’s going to carry forward more central to your view of the asset? And then second, you referenced $4 an Mcf in your plan, but we’re a good, call it, 20%, 30% below that as you sit here this morning. So is there any flexibility in what you’re going to do in the Tupper in ’23?

Roger W. Jenkins — President & Chief Executive Officer

Eric’s going to handle that for you, Charles.

Eric M. Hambly — Executive Vice President, Operations

Okay. First, let me address the well performance issue that we experienced in the fourth quarter. We were able to pretty successfully execute our planned program in 2022. As we highlighted, we brought online 20 new wells. One consequence of permitting restrictions that were experienced last year is about half of those wells were producing into a facility-constrained system. So the wells were producing at a near — basically a flat rate because we were not able to construct debottlenecking pipeline. And we expected that those wells that were producing at a flat rate because of a facility constraint would remain effectively flat through the fourth quarter. As we progressed late into the fourth quarter, we saw that the wells through natural decline came down below that facility constraint. And it was a little bit challenging for us to model exactly when that would happen based on the data we have through constrained wells.

So I would characterize that as a onetime and our forecast going forward reflects the performance of the wells, and that’s reflected in our guidance here today. From a gas price perspective, we did model 2023 at an average of CAD4 AECO as you noted. What I would try to provide some color around sensitivity because it is quite sensitive. For every roughly CAD0.50 AECO, you might see something in the 1,500 to 2,000 BOE net impact on annual average. So you can use that as a go by if you have a different perspective on gas price, you can kind of get a sensitivity for how much production might go up or down based on a $0.50 increase or decrease on the AECO price. Hopefully, that addresses your question.

Roger W. Jenkins — President & Chief Executive Officer

One more bit of color on that, Charles. While there’s a lot of talk about royalty in the Montney, new wells now under their regime for the first year only pay a 5% royalty. And even at this elevated price, as you stated this morning we’re about 14%. Well, every day in the Haynesville and the Marcellus, it’s 25%. So a lot of talk, but it’s always below the United States.

Eric M. Hambly — Executive Vice President, Operations

Just one last comment while we’re talking about Tupper. You may have noted that on January 18 of this year, the Bluebird River Nations entered into an agreement with the province of British Colombia regarding the infringement of treaty rights. And while that agreement is significant and impactful to those E&P companies that are affected on public lands, Murphy’s acreage is on private lands. And we do not expect any go-forward limitations on our ability to execute our program because we’re on private lands based on our understanding of the agreement that was just reached.

Charles Meade — Johnson Rice — Analyst

Got it. That’s all helpful detail. And then Roger, you guys had that dry hole down in Mexico that you already disclosed, but you’ve got a big block down there, and you’ve got a lot of other prospects down there. So can you tell us what you’ve found, what you learned with this first well? And kind of give us a kind of what — how it’s going to inform your future activities down there?

Roger W. Jenkins — President & Chief Executive Officer

Thanks for that question, Charles. Yes, it’s a disappointing well. It was a well that we have in a system. If you really look at the wells in my review, which is still ongoing, we’ve had some trouble getting the data out of the equipment there that we have. It’s a little bit slowed in our review at this time. But it’s really just not enough reservoir there was the issue and where would the reservoir be. There’s a key well being drilled by another operator to our north here this year. We also have our Cholula acreage that we can go back to or review at a later time. And so we’ll be watching that key well to the north and going through our learnings, not ready to move that off, but we have significant acreage. We have many prospects in our company, and we have that same acreage block 5 in the Gulf, the same acreage in Brazil, the same acreage in Potiguar basin. So we have four areas of the same acreage that we have net across our business.

We’re really only spending about $100 million a year on exploration, which includes seismic, the people that work on it and the drilling, and we’ll continue to do this. And these wells are really about seeking opportunities with better returns than what we have in our business. But as we disclosed today, multitude of opportunities to keep our offshore business flat well into ’27 and beyond, all documented, all known thousands of wells in our onshore business. So we can stay sustainable. And all the things I mentioned today about our future does not include one drop of oil from exploration success. So it’s something we do unique that puts us well positioned in a differentiation to others. We’ll have plenty of stuff to do on our own outside of that as well.

Charles Meade — Johnson Rice — Analyst

Thank you, Roger.

Roger W. Jenkins — President & Chief Executive Officer

Thank you. Appreciate it.

Operator

Thank you. Next question, we have Leo Mariani with MKM. Please go ahead.

Roger W. Jenkins — President & Chief Executive Officer

Good morning, Leo.

Leo Mariani — MKM — Analyst

Hey, good morning. I wanted to start off and just address the Eagle Ford a little bit here. I think if I was reading the slides right, I think you guys are forecasting that production is down maybe around 7% year-over-year. It looks like it’s also down a fair bit in the first quarter of ’23 versus 4Q, but I know you guys disclosed some downtime there and just kind of some information about the timing of the wells. And then I guess if I’m reading this right, it looks like you already have maybe a few more operating wells in ’23 versus 2022. So could you maybe just kind of talk through Eagle Ford in terms of why you’re seeing a decline there? I was kind of thought the plan was to try to hold that flat over the next handful of years.

Roger W. Jenkins — President & Chief Executive Officer

Actually, Leo, the plan — I appreciate that question. Actually, it plans to be 30,000 to 35,000 to maximize free cash flow in the Montney, same thing, trying to grow that asset to fill the plants while producing free cash flow. So free cash flow generation is the number one goal. But Eric’s going to address all your questions here right now.

Eric M. Hambly — Executive Vice President, Operations

Yes. Okay. Thanks, Leo. There are two primary factors that are driving lower production with sort of similar well counts relative to 2022. First of all, our new 2023 wells come online a bit later in the year on average than our ’22 program. So when you do the average for the year, it’s a little bit lower. Second, and probably most significantly, our operated 2023 program is almost evenly split between Karnes, Catarina and Tilden locations. And as we’ve highlighted on our recent calls, we delivered significantly improved Karnes and Catarina results in ’21 and ’22 by applying our enhanced completion design. We have not drilled and operated Tilden well since 2019. So we’re hopeful that our 2023 Tilden wells will see the same level of performance improvement as our recent Karnes and Catarina wells. However, our guidance for ’23 for Tilden is based on type curves that are aligned with pre-2020 wells. So a combination of the mix and our expectations for an area we haven’t been to is sort of driving our average production per well down a bit from what we actually experienced in 2022.

And as Roger noted, we’ve been targeting production from the Eagle Ford in the 30,000 to 35,000 barrel a day range. We have, in the last two years, exceeded our expectations from the capital we’re deploying there, getting higher realized production than we expected. We would love for that to happen in ’23, but we are not assuming that it will.

Leo Mariani — MKM — Analyst

Okay. That’s very helpful color there on the Eagle Ford. I just wanted to follow up and ask a little bit about capex here. As I look at the plan for 2023, very, very front-end loaded, 70% in the first half, 30% in the second half. I know you guys also were front-end loaded as well in 2022. However, as kind of the year progressed, you guys did kind of make the decision to raise capex. I know there were some extra projects to get in there. I’m just trying to get a sense here. You’ve got a pretty wide range of capex in terms of what you have there in 2023. I guess I’m just trying to understand if there’s a talk a little bit between kind of the bottom end and the high end of the range? And is there potential for other activity to come on late in the year, if you guys decide to do more in the Gulf, if partners are proposing wells. Maybe just kind of talk through that dynamic a little bit.

Roger W. Jenkins — President & Chief Executive Officer

Thanks for that question. I appreciate that, Leo, this morning. The way we think about it is we — it’s quite common to have a wider range for many of our other peers. So I would be dumb not to have one for myself. We don’t — I don’t see as many — like last year, we’re drilling Khaleesi, Mormont, Samurai. We had incredible success there and we were seeing additional zones to complete. We found some additional pay. This year’s program, we’re completing a known well that we — another very successful well at Dalmatian. So we know what that is. We’re drilling a well at Marmalard, development well up in the middle of several other wells to accelerate that production. So I anticipate like another Marmalard coming out of it.

The risk we have on capex is phasing by super majors in and out of OXY and Chevron involving Lucius and St. Malo. There’s a lot of activity. Eric just talked about the Tilden area, longer laterals are coming to the Tilden area by many big players, meaning that you cover a lot of activity there with longer laterals and new completion techniques coming in Tilden. Could we be AFE for some non-op wells on the border of our acreage? Probably yes. Not large amounts of capex at all. We, across a wide array of businesses, we have very successful assets. That could be things to come our way. I don’t see it the same as last year because a lot of that was driven by Samurai 5 and some things we were doing that were very, very positive for us and greatly positive for us now. And so that’s how I see that, Leo. And I think it’s appropriate to have a range today so that — so you don’t write about it every morning when I have to spend a $0.05 more primarily.

Leo Mariani — MKM — Analyst

Yes. Understood on that, for sure, Roger. Okay. I appreciate that. And then maybe just lastly for me, just a follow-up on capital returns here this year. Just on the way it’s sort of laid out, should we expect that the buyback is going to kick in relatively soon. You obviously raised the dividend here, which is nice to see. But in order to kind of hit those numbers, are we going to start to see the buyback kick in here in the first half?

Roger W. Jenkins — President & Chief Executive Officer

It would be not that great in the first half, but we’re trying to — back to your capex question, and Jeff there, it was poking at the end, we really want to keep our capex like to the midpoint of our guidance. We really want to execute this plan and get to buying back this undervalued stock. And it would be — it’s going to be like a lot of things, it’s more back-end loaded Leo, honestly, on that. And we’re focused on it. I carry three spreadsheets with me every day of how I can buy back the stock. So trying to get to it fast as I can.

Leo Mariani — MKM — Analyst

Okay. Thanks, guys.

Roger W. Jenkins — President & Chief Executive Officer

Appreciate you. Thank you.

Operator

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

Roger W. Jenkins — President & Chief Executive Officer

Good morning, Paul.

Paul Cheng — Scotiabank — Analyst

Hi. Good morning, guys. How you doing?

Roger W. Jenkins — President & Chief Executive Officer

Doing good.

Paul Cheng — Scotiabank — Analyst

Several questions real quick. In Tupper Montney, when do you think you will reach the 500 million cubic feet per day growth now?

Roger W. Jenkins — President & Chief Executive Officer

I’ll let Eric handle that. Go ahead, Eric.

Eric M. Hambly — Executive Vice President, Operations

Paul, we expect that that will happen in our 2024 program. This year [Speech Overlap] Well, typically, for our Tupper Montney asset, we have a first half of the year weighted capital program. So when we bring online our 2024 wells, we ought to be — we expect to be a plant full capacity.

Paul Cheng — Scotiabank — Analyst

So the second half?

Eric M. Hambly — Executive Vice President, Operations

Midyear, say in ’24 third quarter.

Paul Cheng — Scotiabank — Analyst

And at that time, what will be net to you? So should we just assume 500 and take 14%-royalty out and that would be coming on that?

Eric M. Hambly — Executive Vice President, Operations

Yes. Obviously, Paul, it’s quite sensitive to your assumption on the price. When we are in AECO prices in the, let’s say, CAD2.5 to CAD4.50 range, the royalty is extremely sensitive. So based on your view of what the price will be, you can see something from as low as, say, 5% royalty to as high as 20% royalty. We expect gas prices will come down and our net will improve beyond 2023, but that’s kind of up to you to make your own assumption I think.

Paul Cheng — Scotiabank — Analyst

And Eric, can you remind me, I think you have 100% working interest in all those areas, right?

Eric M. Hambly — Executive Vice President, Operations

In Tupper Montney, yes, sir.

Paul Cheng — Scotiabank — Analyst

Right. Okay. And second question, was in your longer-term plan, you’re saying that by 2026, ’27, you are targeting about 210, I think, is the range of 200, 220 that you talk about for the next several years that you’re talking about a about 195. What will cause the increase? Where is the area of the increase that lead you to a higher production in the outer years?

Roger W. Jenkins — President & Chief Executive Officer

Thanks, Paul, for that question. I appreciate. You probably didn’t have a couple of questions. The room was ahead of you. You got to get more. As you look across our production from ’23 onwards, as I look at our onshore business, as you just mentioned and Eric greatly answered about our increase in the Montney, so when you look across our onshore business today, this year, as we just disclosed this morning, 89,000 barrels a day, that’s creeping up 90, 110, 112, primarily around the Montney and maintaining the Montney and toward the end of the program, increased close to 40 in the Eagle Ford at this time. So that — so the onshore is growing. Our offshore business is a very solid business as we disclosed to date. We look to maintain this business between 90,000 and 100,000 through — from now through ’27. But in 2024, ’25 and ’26 as we put on all these projects that we mentioned this morning and have the success of Terra Nova coming back on, which is an incredible project for us, we really get close to 100 in that business through ’25 and ’26, leading to this 180, 190, 210, 210, 210, 210 type business. Real proud of it. It makes enormous free cash flow, Paul, enormous.

Paul Cheng — Scotiabank — Analyst

And the final one, I want to go back to the earlier question on Eagle Ford. And I think Eric is saying that the reason why production is lower because you are drilling the well in the Tilden, right? And if that’s the case, that I mean why go back and drill the Tilden, why not concentrate on Kings and Catarina? [Speech Overlap] Does that mean that we already finished most of the best wells over there? Or I mean, what’s the reason behind?

Roger W. Jenkins — President & Chief Executive Officer

Eric is so excited to answer your question, Paul, I’m going to let him do it. He’s writing notes. He’s going to — go ahead, Eric. I don’t want to hold that back, that energy.

Eric M. Hambly — Executive Vice President, Operations

Paul, we have under our lease agreements with the owners of acreage there in the Tilden area. Some of our leases have some ongoing drilling commitments that every year or two or three, you have to drill another well or four. And our program in 2023 is oriented toward fulfilling those obligations. But also, as we highlighted earlier, we really would like to see how well they perform with our enhanced completion design. So we might be able to see a larger amount of top-tier performing wells there, but it’s primarily around fulfilling our obligations and maintaining our leases.

Roger W. Jenkins — President & Chief Executive Officer

Well, on top of that, Paul, if you look at many companies you cover, there’s a lot of rigs moving into Tilden, there’s a lot of activity because that’s through the Permian, and we’ve been doing a long time in the Montney, 10,000-foot laterals are becoming very common. And then companies are working together more in the Tilden area because it’s an underdrilled area in the Eagle Ford to add these longer laterals, which the industry believes will be higher production. Our Karnes and Catarina can’t be extended in that way. And if there’s a game plan, very sophisticated, planned out plan to have offset frac impacts and how we move from Karnes to Catarina and now Tilden and it’s a game plan that allows us to maintain this 30 to 35 for a very long time and grow it to any level we want and make a lot of money in the business. So just a year, we’re going back to Tilden, I personally believe that our — all the great work we did on technology around fracking will succeed there as well. And it’s clear to me about the rig count and what’s going on that others believe that as well.

Paul Cheng — Scotiabank — Analyst

Great. Eric, I just want to — one follow-up on the obligation. For the next several years, do you also have a launch obligation that you have to drill in Tilden?

Eric M. Hambly — Executive Vice President, Operations

I have to look at that to get into the details, but I wouldn’t view it as a large obligation. It’s been relatively minor, and we’ve been able to manage it within our optimal capital allocation framework. So yes, I don’t have a very clear answer for you right now. I wouldn’t expect it to be significant.

Roger W. Jenkins — President & Chief Executive Officer

Paul, every company you cover has drilling obligations in the Eagle Ford.

Paul Cheng — Scotiabank — Analyst

I understand. I just want to see that whether we’re going to see the next several years that you’re also going to drill a fair bit in Tilden because of the obligation or not.

Roger W. Jenkins — President & Chief Executive Officer

Well, as Eric said, we don’t see that as an issue to hit the volumes for the capex we have. But I can see and understand your question on that, and we appreciate it.

Paul Cheng — Scotiabank — Analyst

Okay. Thank you.

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Paul. See you soon.

Operator

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

Neal Dingmann — Truist Securities — Analyst

Morning, Roger, I’ll try to just keep mine to one or two to keep things moving along the day.

Roger W. Jenkins — President & Chief Executive Officer

No, you got to get in here. You got to get there for, compete.

Neal Dingmann — Truist Securities — Analyst

Roger, my question is obviously done a fantastic job on the list made, the more month Samurai fuel development. Could you just remind us, I assume the plans are there just to try to keep that production relatively flat on Kings Quay? And if so, is that — will that entail just what a well — one or two wells a year? Or how should we sort of think about over the next one to two to three years, how do you want us to think about that play?

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Neal. Thanks for that question on our great asset now the largest asset in our company, an incredible asset. The way to think about it is Samurai 5 is a great deal for us. We now think that Samurai could be near 100 million barrel discovery from exploration out there, very proud of it. We’ll have three wells there. Of course, we already have two there and then we have the other wells in the other field at Khaleesi, Mormont. Each of these have recompletion up hole and different ways to add perforations and doing things around technology to add additional zones. There’s a lot of zones in these wells through all those efforts, which would be just through opex and some de minimis capex will allow it to be added. To keep this slide, there’s not a plan today of an additional well in the next three-year period that we’re advertising to remain flat. There is some in wellbore things to be done that are de minimis capital to keep it flat with the same resource base.

Neal Dingmann — Truist Securities — Analyst

Great to hear. And then just a follow-up. You did a good job on looking again on Slide 28, where you show remarkable 60-plus years in the Eagle Ford and Duvernay inventory. I’m just wondering, would you all consider — I mean, again, just I don’t know, maybe pay debt down quicker or even include pop that shareholder return quicker. Would you all consider divesting any of the assets given obviously, there’s a high need by many of your peers for inventory and what appears to be the market not giving you, I don’t think, full credit for that position?

Roger W. Jenkins — President & Chief Executive Officer

Well, I appreciate that, Neal, and we have been very active in M&A, both buying and selling $8 billion of deals in eight years. However, this is part of our business to be a sustainable business, and I’ve rattled off to Paul a few minutes ago, 210,000 for a long time without exploration success without M&A and delivering billions of dollars to our shareholders. And it’s going to — it’s just a lot to unravel that. It gives stability to our offshore business. It’s all weighted, it’s unique. And people make — the price to buy, it may keep going up, Neal, because it’s probably not going down. So we’re happy with what we have. We have a solid business, long haul here without doing anything and going to need to execute into that and start returning to shareholders before we consider that type of opportunity right now.

Neal Dingmann — Truist Securities — Analyst

Great answers. Thanks, Roger.

Roger W. Jenkins — President & Chief Executive Officer

Thank you. Appreciate it.

Operator

[Operator Instructions] Your next question comes from Neil Mehta with Goldman Sachs. Please so ahead.

Neil Mehta — Goldman Sachs — Analyst

Yes. Good morning, Team.

Roger W. Jenkins — President & Chief Executive Officer

Good morning, Neil.

Neil Mehta — Goldman Sachs — Analyst

Morning Roger. First question is around bolt-on M&A. You’ve done some really good stuff, particularly in the Gulf of Mexico. Just what do you think the prospects are there, especially given the — all that’s going on in Brazil right now, but curious your views on the opportunity set?

Roger W. Jenkins — President & Chief Executive Officer

Thank you, Neil, for that question. It’s been a real key for us as people that followed us like Goldman for a long time came out of Malaysia, paying extensive cash taxes, got our money repatriated, bought things at very good prices in the Gulf, produced way more than we originally planned and paid — and another advantage to Murphy is that we pay no cash taxes all the way into early ’25. So incredibly well positioned with that transaction.

We look at this. We consider ourselves the leader in M&A and execution in the Gulf. Everything is brought to Murphy to review. We have incredible database and knowledge and experience around Gulf of Mexico deals. We know every deal. We know every field. And these things continue to come. We, though, are very particular and we have a particular process around focusing on the resource first and what we will pay, oftentimes, people ask about the bid/ask. It doesn’t matter to Murphy because we get a price we’re going to pay, and we don’t care about the word bid/ask.

So we look at them closely, look at them with our framework, what will it do to the framework, how can it be financed and still try like heck to keep the framework because we really want to get into that as soon as we possibly can. So all those factors come to bear. And we have a certain type of return and a certain type of EBITDA multiple that we look for. And when those come up, we will execute on those, but not looking at any big deals that require altering our — significantly altering our capital structure. But look at a lot of things, a lot of people come to us to partner with them, a lot of situations coming our way due to our outstanding operatorship. As a matter of fact, we’re being promoted into drilling a well for the first time due to our operating ability.

So a lot of things coming our way due to our unique operational skill set that we’re very proud of. So we’re looking at them, and we’ll look at all of them, but we have a really tight criteria that we don’t share around that Neil, but looking at that, and I appreciate your question on it.

Neil Mehta — Goldman Sachs — Analyst

All right. Great. And the quick follow-up is just you talked about it in the comments around capex, but we’re seeing signs of offshore inflation and things like rig rates and service commentary. How are you guys mitigating it? And what do you see in firsthand?

Roger W. Jenkins — President & Chief Executive Officer

Thanks for that question, Neil. Of course, your company covers all these drillers and everything, our friends. When you’re in the business like we have been, today, we have two drillships in the Gulf. We recently had three floating rigs in Mexico and the Gulf. We’re an active player, and we have a program. When you’re an active player, you’ll have the lower or middle part of the market and a bit of the high end. If you’re constantly in the business, you very rarely pick up all on the high end. So I’d say the higher program today is at the lower end of rates in the 300 max, and we have some at the 400 level, which is the market today. It’s kind of impossible not to have something at the market unless you really contract for a long time. So we feel well positioned. Other inflationary things really around people costs, and we’ve talked about this before. There’s really not a big increase in rig count in the Gulf of Mexico, which keeps the inflation at bay a little bit on other services. Of course, in the onshore post-COVID, it went up from all the way to 700-and-something rigs. So the rig count is increasing and the DUCs are increasing, the frac pressure is more than we see offshore. But really, in our business, Neil, it’s about days on location and executing because you’ll have every kind of rate there is if you’re in this business for a long time.

Neil Mehta — Goldman Sachs — Analyst

All right. That’s great color, Roger. Thank you.

Roger W. Jenkins — President & Chief Executive Officer

Appreciate. Thank you, Neil.

Operator

Your next question comes from Geoff Jay from Daniel Energy Partners. Please go ahead.

Geoff Jay — Daniel Energy Partners — Analyst

Hi, Good Morning. Just real quick for me. So in the Eagle Ford, I was just wondering how the cadence of activity is going to play out for the year? Obviously, you guys were rough numbers around two rigs pretty much every quarter last year with the third rig in the fourth quarter. Given how the capex is going to tail in 2023, I was just kind of wondering what you suspect where you thought your cadence of activity would look like for the rest of the year in the Eagle Ford? Thank you.

Roger W. Jenkins — President & Chief Executive Officer

I’ll have Eric answer that far you, sir. Right away here.

Eric M. Hambly — Executive Vice President, Operations

Yes. We have a slide, number 22, which shows the cadence of our onshore program. We detailed the Eagle Ford program as well as our Tupper Montney program there, both operated and nonoperated. So you can see that it’s 10 Karnes wells come online in the first quarter. And then the second quarter is our biggest quarter from Eagle Ford activity with the third quarter contributing kind of similar level of the first quarter.

Geoff Jay — Daniel Energy Partners — Analyst

Okay. But I mean — so I guess my question really is, are you going to sustain a three-rig program for the remainder of the year in Eagle Ford? Or will that drop down to two at some point? Or sort of how you see that program flexing?

Eric M. Hambly — Executive Vice President, Operations

Yes. So in terms of drilling activity, we have four rigs working right now, two in Tupper and two in the Eagle Ford, and they will all be out of work by the third quarter.

Geoff Jay — Daniel Energy Partners — Analyst

Okay. Thank you, guys, for clarifying. Thanks a lot.

Roger W. Jenkins — President & Chief Executive Officer

Appreciate it.

Operator

And there are no further questions from our form 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

We appreciate everyone focusing on our call today and asking good questions. We appreciate that way to talk about our company and a great year ahead. Any questions you have, please get with our IR team here. And we look forward to seeing you in our next quarter, and I appreciate all the help. Thank you.

Operator

[Operator Closing Remarks]