Murphy Oil Corporation (NYSE:MUR) Q4 2022 Earnings Call Transcript

Murphy Oil Corporation (NYSE:MUR) Q4 2022 Earnings Call Transcript January 26, 2023

Operator: Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2022 Earnings Conference Call. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Kelly Whitley: 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 Jenkins: 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 excepts, 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 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; we — as we continue focusing on our 4 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 Samurai project, where we initiated production ahead of schedule, and we continue to reduce above expectations.

Additionally, the King’s Key facility maintains an industry-leading uptime average of 97%. Then, I’m sure we executed a 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 2 more operated exploration wells in the Gulf of Mexico early this year. On Slide 4. In the fourth quarter, we produced 173, 600,000 barrels of oil equivalent per day 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. We — 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 $364,000 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?

Tom Mireles: 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 has proved developed reserves to 60% from 58% of total crew 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 0 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: 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; the — 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 was 72% liquids weighting. For full year 2022, we produced 6,000 barrels of oil equivalent per day with 74% liquids and brought on line 3 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 maintain 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, 2 non-operated Lucius wells were brought online in the fourth quarter of 2022 and the first quarter of 2023, while the non-operating project is progressing towards completion in early 2024.

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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 3 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 5 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 Jenkins: Thank you, Eric. On Slide 20. Our 2023 capital plan has a range of spending of $875 million to $1.025 billion. More than 2/3 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 decide 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 oil pricing — 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 $175.5 million to 183,500 barrels equivalent per day with 99,000 barrels of oil per day or 5% and 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 produced approximately 313 million cubic feet per day, assuming a C4 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 2 non-operated Lucius wells and a non-operated development in the St. Malo field. The non-operated Satale 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 and 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 Terranova 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 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 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 ’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 repurchasers to a variety of methods with no time living. 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 enhanced 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. — 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 2 basins, we hold more than 60 years of inventory in Murphy Oil today. In Tupper Montney, Murphy Hells 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 US$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 an additional 5 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 3 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 Key, which we 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. A it 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 3 operated exploration wells in the Gulf. As for the future, we on the 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.

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Q&A Session

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

Arun Jayaram: 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 Jenkins: Is a mixture of me and Eric and on 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 4 drilling rigs in North America drilling and only 1 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 can let in a minute.

We have Terranova 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 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 Hambly: 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.