Earnings Call Transcript - MUR Q4 2022

Operator, Operator

Good morning, everyone, and welcome to the Murphy Oil Corporation Fourth Quarter 2022 Earnings Conference Call. I will now hand the call over to Kelly Whitley, Vice President of Investor Relations and Communications. Please continue.

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 non-controlling 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 Jenkins, President and 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, 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, and Samurai fields in the Gulf of Mexico. Murphy has an ongoing exploration portfolio, and we’re in the process of a 3-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: delever, execute, explore, and return; I'm very pleased with the progress we have made as a company. In 2022, Murphy achieved our $650 million debt reduction goal, resulting 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 Samurai project, where we initiated production ahead of schedule and continue to outperform expectations. Additionally, the King’s Key facility maintains an industry-leading uptime average of 97%. I'm sure we executed a well delivery program well with 40 operated wells and 15 gross non-operated 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 173,600 barrels of oil equivalent per day at 62% liquids. Due to the significant impact from our Khaleesi, Mormont, and Samurai field development, we achieved nearly 30% growth in our oil volumes to 97,000 barrels per day 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. 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 the full year '21. Our accrued CapEx for the year totaled $1.016 billion, excluding non-controlling 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 $364,000 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 Mireles, 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. With average annual CapEx of approximately $880 million, excluding non-controlling 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 reserves, 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 the 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 the fourth quarter 2022. With advantaged oil price realizations, we generated significant cash from operations, including non-controlling 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 generated 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 two 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 Hambly, Executive Vice President of Operations

Thank you, Tom, and good morning, everyone. Slide 11; our Eagle Ford Shale wells produced an average of 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 of 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 the 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 a 72% liquids weighting. For full year 2022, we produced 6,000 barrels of oil equivalent per day with 74% liquids and brought online 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 an 80% oil weighting. Our Gulf of Mexico production was up 10% for the year. I'm pleased with 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 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 Key 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 total depth 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 forecasted to cost approximately $26 million net to Murphy. With that, I will turn it back to Roger.

Roger Jenkins, President and Chief Executive Officer

Thank you, Eric. On Slide 20, our 2023 capital plan has a range of spending from $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 should also 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. On Slide 21; our first quarter 2023 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 than the fourth quarter, it reflects our natural production decline due to the first-tax weighted capital expenditures that we use yearly as we haven't brought online an operated well in our Eagle Ford shale since September and in the Tupper Montney since July. For the full year 2023, we forecast a production range of 175,500 to 183,500 barrels equivalent per day with 99,000 barrels of oil per day or 5%. Overall, with lower forecasted CapEx for 2023, this guidance represents a 10% oil growth for the year and a 7% total production growth. Moving now to Slide 22; our total onshore budget for 2023 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 quarters. 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. Our Tupper Montney asset is planning $125 million, forecasting to bring online 16 operated wells, and produce approximately 313 million cubic feet per day, assuming a CAD 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, with 57% oil and 69% liquids in that asset. Turning to our offshore business on Slide 23. Our plan here calls for a $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 Satale waterflood project continues to be planned. We'll be progressing this year. For full year 2023, 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 produced in 2022. 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 in advance 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 of equivalent 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 2022. Next, we plan to spud the operated long call well late in the first quarter before moving to a spud of a third operator Gulf of Mexico well towards the middle of 2023. We're still working on 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, allowing Murphy to repurchase through 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 2023 through 2025 is to follow our capital allocation framework with approximately 40% of our operating cash flow reinvested through 2025 with an average annual CapEx of $900 million. 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 2026 and 2027, 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. Furthermore, our ongoing reinvestment of approximately 40% of operating cash flow forecasts 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 three producing areas as of year-end 2022. 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 stands alone with approximately 12 years of inventory or 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 USD 1.45 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, while an 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 Murphy 2.0 and allowing us to share 25% of our adjusted free cash flow with our investors. Furthermore, we've continued to delever with a debt reduction goal of $500 million in 2023 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, and Samurai, flowing to King's Key, which we will further be supported by production from our successful Samurai 5 well recently drilled. Also in 2023, we'll be completing a previously drilled well at Dalmatian in addition to a new development well at Marmalard. In our solid year plan in our North America onshore assets, we're drilling more of our award-winning Eagle Ford Shale locations as well as rebounding 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 have strong onshore locations with thousands of high-quality, low-breakeven wells remaining to be drilled in support of our steady long-term production, as well as a sustainable long-term offshore business and ongoing cash returns to shareholders. Murphy remains a long-term stable company with low investment rates, slight production growth, and a growing offshore competitive advantage. Coupled with our keen eye on protecting the environment, we are positioned for long-term success. In closing, 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 the operator and look forward to taking your questions today. Thank you.

Operator, Operator

Thank you. Your first question comes from Arun Jayaram with JPMorgan. Good morning, everyone.

Arun Jayaram, Analyst

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 follow with an update on the St. Malo project in early '24.

Roger Jenkins, President and Chief Executive Officer

It's a mixture of me and Eric on that for you, Arun. Thank you for that question. 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. 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 to go 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, and I'll have Eric comment in a minute. We have Terra Nova coming on. We have to estimate what we feel the turnover will be, and we have that in the second quarter. That will probably be 4,000 to 5,000 our way minimum. We're looking at that whole business being around for the year, and that's what that trajectory is. And I'll just let Eric address the downtime issues we have this quarter and wrap back up to make sure I handle all of your questions.

Eric Hambly, Executive Vice President of 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 8 days of 0 production from the Gulf of Mexico. Just a few more points on production growth. For our offshore business, we have some new volumes coming online from Samurai V, 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, 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 in Tupper Montney volume from the first to fourth quarter, with our wells coming online through the year and being fully online in the third quarter. We ought to see a pretty substantial increase there, and that's how we model our business.

Roger Jenkins, President and 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 fuels 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 for us. So that project continues to go well. But they phase CapEx in and out on the year on occasion as they execute it, and there's a production well that's coming online 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, 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 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 Jenkins, President and Chief Executive Officer

Arun, thank you for that. I take pride in that framework. It’s not iWork. We have adjusted free cash flow as described in the slide, and we will be excluding certain items. This involves factoring in capital expenditures or operating cash flow, subtracting capital spending from the cash flow statement. We also need to account for dividends and contingent payments, as highlighted last year. We will be excluding our NCI payments, quarterly dividends, pension distributions, abandonments, and similar expenses to arrive at adjusted free cash flow. This is detailed on Slide 26. This year, we anticipate experiencing over $200 million, primarily in abandonment and contingent payments. Additionally, our dividend is estimated at about $170 million, which will also be deducted, and we’ll allocate 25% of the remaining funds. This calculation is requested every quarter, and we are working to execute it as quickly as possible.

Arun Jayaram, Analyst

Thank you. Appreciate it.

Operator, Operator

Your next question comes from Charles Meade with Johnson Rice.

Charles Meade, Analyst

Roger, I have many questions, but I'll start with two. Firstly, regarding the Tupper Montney, I'm curious about the well performance you mentioned as a reason for being at the lower end of your production guidance for the quarter. Was this a one-time issue from the fourth quarter, or is it likely to influence your perspective on the asset moving forward? Secondly, you mentioned a $4 per Mcf target in your plan, but currently, we are about 20% to 30% below that. Is there any flexibility in your approach to the Tupper in 2023?

Roger Jenkins, President and Chief Executive Officer

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

Eric Hambly, Executive Vice President of Operations

First, let me address the well performance issue we experienced in the fourth quarter. We successfully executed our planned program in 2022 and brought online 20 new wells. One consequence of permitting restrictions we faced last year was that about half of those wells were operating in a facility-constrained system. As a result, their production was at a near flat rate since we could not build a debottlenecking pipeline. We anticipated these wells would produce at a flat rate due to the facility constraint. However, late in the fourth quarter, the wells experienced natural decline and fell below that facility constraint, which made it somewhat challenging for us to predict when that would occur based on the data from constrained wells. I would consider this a one-time event, and our future forecast reflects the performance of the wells, which is incorporated in our guidance today. Regarding gas prices, we modeled 2023 with an average of CAD 4 AECO. It is important to note that for every CAD 0.50 AECO change, there could be a net impact of approximately 1,500 to 2,000 BOE on the annual average. This can serve as a guide; if you have different expectations for gas prices, you can estimate the potential production changes based on a $0.50 increase or decrease in the AECO price. I hope that answers your question.

Roger Jenkins, President and 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. Even at this elevated price, as you stated this morning, we’re about at 14%. Well, every day in the Haynesville and the Marcellus is 25%. So there's a lot of talk, but it's always below the United States.

Eric Hambly, Executive Vice President of 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 Columbia regarding the infringement of treaty rights. 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. We do not expect any go-forward limitations on our ability to execute our program because we're on private lands and based on our understanding of the agreement that was just reached.

Charles Meade, Analyst

Got it. That's all helpful detail. Roger, you had a dry well in Mexico that you already reported, but you also have a large block there and many other prospects. Can you share what you discovered and learned from this first well? Additionally, how will this inform your future activities in that area?

Roger Jenkins, President and Chief Executive Officer

Thanks for that question, Charles. Yes, it's a disappointing well. It was a well that we have in the 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 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 this year. We also have our Cholula acreage that we can go back to in our 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. We have that same acreage block 5 in the Gulf, the same acreage in Brazil, the same acreage in the PortoGra 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. These wells are all about seeking opportunities with better returns than what we have in our business. But as we disclosed today, we have a multitude of opportunities to keep our offshore business flat well into 2027 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. It's something we do uniquely 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, Analyst

Well, thank you. Appreciate it.

Operator, Operator

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

Leo Mariani, Analyst

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 2023 versus Q4, 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 are to have maybe a few more operated 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 Jenkins, President and Chief Executive Officer

Actually, Leo, the plan is to reach 30,000 to 35,000 to maximize free cash flow in the Montney. The goal is to grow that asset to fill the plants while generating free cash flow. So, free cash flow generation is the number one priority. But Eric will address all your questions right now.

Eric Hambly, Executive Vice President of 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 2022 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 a 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 sort of driving our average production per well down a bit from what we actually experienced in 2022. 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, Analyst

Okay. That's very helpful on the 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 caught a little bit between 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 Jenkins, President and Chief Executive Officer

Thanks for your question, Leo. We believe it’s quite standard for many of our peers to have a broader range, so I see the value in having one for ourselves. Unlike last year, where we focused on drilling Khaleesi, Mormont, and Samurai with great success, this year's program involves completing a non-well and progressing with a successful well at Dalmatian. We are currently drilling a development well at Mamelodi amid several others to boost production, and I expect to see additional positive results from that. The risk related to our capital expenditures comes from the varying phases of super majors like Oxy and Chevron, particularly involving Lucius and St. Malo, which is generating a lot of activity. Eric mentioned the Tilden area, where longer laterals are being introduced by several major players, which indicates significant operations there due to new completion techniques. We might consider non-operated wells at the edge of our acreage, but the capital expenditure there would be minimal. Overall, we have a diverse portfolio of successful assets that may present future opportunities. However, this year feels different as last year's performance was heavily influenced by Samurai 5 and other very advantageous activities for us. That's my perspective, Leo. I find it reasonable to maintain a range today to avoid daily scrutiny over any minor changes in our expenditures.

Leo Mariani, Analyst

Yes. Understood on that. For sure, Roger. Okay. I appreciate that. And then maybe just lastly for me, just to 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 hit those numbers, are we going to start to see the buyback kick in here in the first half?

Roger Jenkins, President and Chief Executive Officer

It might not be ideal in the first half, but regarding your question about capital expenditures, we want to keep our CapEx at the midpoint of our guidance. We are committed to executing this plan and ultimately buying back our undervalued stock. Honestly, it will be more back-end loaded. I am focused on managing three spreadsheets daily to strategize our stock buyback, and I'm trying to move as quickly as possible.

Leo Mariani, Analyst

Okay. Thanks. Appreciate it.

Operator, Operator

Next question comes from Paul Cheng with Scotiabank.

Paul Cheng, 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 Jenkins, President and Chief Executive Officer

I'll let Eric handle that, go ahead, Eric.

Eric Hambly, Executive Vice President of Operations

Paul, we expect that that will happen in our 2024 program.

Paul Cheng, Analyst

So the second half?

Eric Hambly, Executive Vice President of Operations

Mid-year say 2024, third quarter.

Paul Cheng, Analyst

And at that time, that what will be met to you, so should we just assume 500 and take 14% royalty out, and that would become net?

Eric Hambly, Executive Vice President of 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. 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.

Paul Cheng, Analyst

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

Eric Hambly, Executive Vice President of Operations

In Tupper Montney, yes.

Paul Cheng, Analyst

Okay. And second question, in your longer-term trend, you're saying that by 2026, '27, you are targeting about 210, I think it's the range of $200 million, $220 that you talk about for the next several years that you're talking about 195%. So what will cause the increase? Where is the area of the increase that leads you to a higher production in the outer years?

Roger Jenkins, President and Chief Executive Officer

Thank you, Paul, for your question. I understand you might not have had it a couple of questions ahead. Looking at our production from 2023 onwards, particularly in our onshore business as you just mentioned, we are seeing increases in the Montney. This year, we've disclosed that we are producing 89,000 barrels a day, which is approaching 90, 110, 112, mainly due to the Montney and maintaining its production. By the end of the program, we expect an increase close to 40 in the Eagle Ford at this time. Our onshore operations are indeed growing. Our offshore business is also performing well, as we mentioned today, and we aim to maintain production between 90,000 and 100,000 through 2027. However, in 2024, 2025, and 2026, as we implement the projects we discussed this morning and benefit from the return of the Terranova project, we anticipate reaching close to 100 in that sector during 2025 and 2026, ultimately leading to production figures around 180 to 210. I'm very proud of this progress as it generates significant free cash flow, Paul.

Paul Cheng, Analyst

I want to revisit the earlier question about Eagle Ford. Eric mentioned that the lower production is due to drilling the well in Tilden. If that’s the case, why are we going back to drill in Tilden instead of focusing on Kings? Does this mean we have already completed most of the best wells in that area, or what’s the reasoning behind this?

Eric Hambly, Executive Vice President of Operations

This is Eric, so excited to answer your question, Paul. I'll let him do it. He's right in notes. He's going to Craig.

Roger Jenkins, President and Chief Executive Officer

Go ahead, Eric. I don't want to hold that back, that energy.

Eric Hambly, Executive Vice President of 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. 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 Jenkins, President and Chief Executive Officer

There is a lot of activity in the Tilden area due to the number of rigs moving in, particularly through the Permian, and we’ve been active in the Montney for a long time. The use of 10,000-foot laterals is becoming increasingly common. Companies are collaborating more in Tilden since it is underdrilled in the Eagle Ford, allowing for the addition of these longer laterals, which are expected to lead to higher production. Our operations in Catarina can't be extended in this manner. If there is a well-planned strategy to manage frac impacts as we transition from Karnes to Catarina and now Tilden, this plan enables us to sustain production levels of 30 to 35 for an extended period and grow it significantly, allowing us to profit substantially from the business. We are returning to Tilden this year, and I am confident that the technological advancements we achieved in fracking will be effective there as well. It is evident to me, based on the rig count and current developments, that others share this belief.

Paul Cheng, Analyst

Eric, I just want to follow up on the obligation. For the next several years, do you also have a large obligation that you need to drill in Q2?

Eric Hambly, Executive Vice President of Operations

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

Paul Cheng, Analyst

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

Roger Jenkins, President and 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. We appreciate it. Thank you, Paul.

Operator, Operator

Your next question comes from Neal Dingmann with Truist Securities.

Neal Dingmann, Analyst

Roger, I'll try to just keep mine to one or two to keep things moving along today.

Roger Jenkins, President and Chief Executive Officer

No, you got to get in here.

Neal Dingmann, Analyst

Can you provide an update on the plans for maintaining production levels at Kings K? Will that involve drilling one or two wells each year? How should we think about the developments in that area over the next couple of years?

Roger Jenkins, President and 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 Sari could be near a 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 Claremont. Each of these have recompletion uphole and different ways to add perforations and deferring things around technology to add additional zones. There's a lot of zones in these wells that 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, Analyst

It's great to hear. I have a follow-up regarding Slide 28, which highlights the impressive 60-plus years of inventory in the Eagle Ford and Duvernay. I'm curious if you would consider accelerating debt repayment or potentially enhancing shareholder returns. Would you contemplate divesting any assets, especially given the significant demand from many of your peers for inventory and the apparent lack of full market recognition for that position?

Roger Jenkins, President and 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 8 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. It's just a lot to unravel that. It gives stability to our offshore business. It's all weighted, it's unique. 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 about 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, Analyst

Thank you. Appreciate it.

Operator, Operator

Your next question comes from Neil Mehta with Goldman Sachs.

Neil Mehta, Analyst

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 all that's going on in Brazil right now, but curious your views on the opportunity set.

Roger Jenkins, President and Chief Executive Officer

Thank you, Neil, for that question. It has been crucial for us that investors like Goldman have supported us for a long time. We came out of Malaysia, paid significant cash taxes, successfully repatriated our funds, acquired assets at attractive prices in the Gulf, and produced significantly more than we initially anticipated. Additionally, Murphy is in a favorable position, as we will not be paying cash taxes until early 2025. This places us in an excellent position regarding that transaction. We view ourselves as leaders in mergers and acquisitions as well as execution in the Gulf. Every opportunity is reviewed by Murphy. Our extensive database, knowledge, and experience with Gulf of Mexico deals are unmatched. We are familiar with every deal and every field. Opportunities continue to arise. However, we approach these prospects with care and follow a specific process focused on the resource and our pricing. Many inquiries arise concerning the bid-ask process, but that does not impact Murphy because we determine the price we will pay without concern for the bid-ask terminology. We analyze every potential deal within our framework, considering how it can be financed while maintaining our standards, as we aim to seize opportunities promptly. We apply various criteria, including expected returns and EBITDA multiples, before proceeding. We are not pursuing large deals that would significantly alter our capital structure. Nevertheless, we evaluate numerous opportunities as many seek to partner with us, driven by our exceptional operational capabilities. In fact, we are being considered for drilling a well for the first time, reflecting our operational expertise. There are many opportunities coming our way due to our unique skills, which we take pride in. We will review all potential deals, but we maintain strict criteria that we do not disclose. Thank you for your question.

Neil Mehta, 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 firsthand?

Roger Jenkins, President and Chief Executive Officer

Thanks for the question, Neil. Our company is involved with all these drillers and similar operations. Currently, we have two drillships in the Gulf and previously operated three floating rigs in Mexico. As an active player in this field, we typically operate in the lower to mid market segments, occasionally touching the high end. It's rare to consistently engage in high-end contracts. At the moment, our program is positioned at the lower end of the rates, around the 300 level, with some at the 400 level, which reflects the current market. It’s challenging to have anything at the market rates without long-term contracts. We feel well-prepared in this regard. Other inflationary pressures mainly relate to personnel costs, which we've discussed before. There's not a significant rise in rig count in the Gulf of Mexico, which helps keep inflation manageable for other services. In contrast, the onshore sector saw a jump post-COVID, reaching over 700 rigs. The rig count is rising, and DUCs are increasing frac pressures more than what we observe offshore. However, in our industry, Neil, success largely depends on the number of days spent on site and execution, as there are various rates available if you're in this business over a long period.

Neil Mehta, Analyst

All right. That's great color, Roger.

Operator, Operator

Your next question comes from Jose from Daniel Energy Partners.

Unidentified Analyst, Analyst

Just real quick for me. So in the Eagle Ford, I was just wondering how the case 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 off in 2023, I was just kind of wondering what you suspect what you thought your cases and activity would look like for the rest of the year in the Eagle Ford.

Roger Jenkins, President and Chief Executive Officer

I have Eric answer that fast right away here.

Eric Hambly, Executive Vice President of 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 non-operated. 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.

Unidentified Analyst, Analyst

Okay. My question is whether you plan to maintain a three-rig program for the rest of the year in Eagle Ford, or will it decrease to two at some point? How do you see that program adjusting?

Eric Hambly, Executive Vice President of 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 in the third quarter.

Operator, 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 Jenkins, President and Chief Executive Officer

I appreciate everyone focusing on our call today and asking good questions. We appreciate the way to talk about our company in 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

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