Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation third quarter 2022 earnings conference call. If at any time during the call you need assistance, please press star zero for the operator. I'd now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead. Thank you, David. Good morning, everyone, and thank you for joining us on our third quarter earnings call today. Joining us is Roger Jenkins, President and Chief Executive Officer, along with Tom Morales, 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 one. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussion of risk factors, see Murphy's 2021 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. Thank you. Good morning, everyone. On top of an excellent quarter, both operationally and financially, with consensus beats across the board, Murphy continues to deliver a strong value proposition. Our ongoing execution excellence, especially in our oil-weighted assets, ensures that we remain a long-term sustainable company as we operate safely and with focus on continual improvement in our carbon emissions intensity. Offshore competitive advantage is reinforced with significant project success, especially with the achievements of the Khaleesi, Mormont and Samurai fields development flowing to the King's Quay floating production system. Murphy has a unique exploration portfolio as we prepare to drill two key wells this quarter. We're generating strong cash flows with higher oil prices and well performance exceeding expectations as we have been able to increase our shareholder returns through quarterly dividend raises, as well as accelerate our debt reduction goals. As a result of this success, last quarter, our capital allocation framework was announced, supporting increasing returns to shareholders in addition to our 60-year long-standing dividend as various debt targets are achieved. On slide three. Our team has done a tremendous job this year progressing our three priorities to delever, execute, and explore. During the quarter, we reduced debt by $248 million across three senior note transactions. Also earlier this week, we announced an additional $200 million redemption of senior notes due in 2025. We're projected to achieve the high end of our $650 million debt reduction goal by year-end and forecast total debt at that time of $1.8 billion, which positions us to, again, Murphy 2.0 of our capital allocation framework in 2023, which will advance cash returns to shareholders. Our ongoing debt reduction would not been achieved if it weren't for a continued successful execution in our operations. We now have six of seven producing wells from the Khaleesi, Mormont and Samurai field development projects, with gross production volumes significantly exceeding expectations and achieving a record 120,000 barrel equivalents per day gross at the facility. In our Khaleesi and Mormont volumes alone, we produced practically double our original estimates used in M&A economics due to project execution. Onshore, we continue to see superior well results in the Eagle Ford Shale from our 2022 program and are pleased to drill and complete Tupper Montney wells in 2022 for an average price of just under $5 million per well, with exceptional payout results. Our exploration program has some exciting months ahead as we prepare to spud two operated wells in the fourth quarter with Tulum in offshore Mexico and OSO in the Gulf of Mexico. Oxy and Ridgewood Energy entered into an agreement with Murphy to participate in OSO well, with Murphy remaining as operator and holding 33.34% working interest. Also during the quarter, Murphy assumed its partner's position in Brazil's Potiguar Basin and now holds 100% working interest in those three blocks. Lastly, as announced earlier in the quarter, our board raised our quarterly dividend, returning it to a pre-2020 level of $0.25 per share or $1 per share annualized. Murphy plans to advance its capital allocation framework and return money to shareholders through repurchases and potential dividend increases as we achieve various debt thresholds. On slide four. In the quarter, we produced 188,500 equivalents per day, 57% liquids, which is the highest oil production level since the second quarter of 2021. This exceeded the high end of our guidance due to several reasons, including a less active Gulf of Mexico hurricane season and strong well performance in the Eagle Ford Shale, which more than offset price-related royalty impacts in the Tupper Montney. Murphy's realized oil price of $93.65 per barrel continued to receive a premium to the WTI benchmark, with NGLs just below $37 per barrel, and natural gas was $4 per Mcf for Murphy. I'll now turn the call back over to our CFO, Tom Morales, for sustainability and financial update. Tom? Thank you, Roger, and good morning, everyone. Slide five. Since releasing our 2022 sustainability report in August, we have received positive responses from the steps we've taken to increase and align our reporting with internationally recognized frameworks as we support efforts across the industry for comparable reporting. As noted in the report, Murphy also received its second annual independent assurance of Scope 1 and 2 emissions data. Following the disclosure shared in our most recent report, we ranked highly with ISS, improving our environmental score by three levels, while our social score was raised one level to the highest rank. Our governance score remains at the highest rank for five years running. Slide six. In the third quarter, we recorded great financial results with net income of $528 million or $3.36 per diluted share. After-tax adjustments included a $189 million non-cash mark-to-market gain on derivative instruments, a $25 million non-cash mark-to-market gain on contingent consideration, and $26 million of other items. As a result, we reported adjusted net income of $290 million, or $1.84 per diluted share. Cash from operations, including non-controlling interest, was $719 million for the quarter. After accounting for net property additions and acquisitions, we achieved positive adjusted cash flow of $390 million. Murphy reported accrued CapEx of $209 million in the third quarter, which excluded non-controlling interest in the Lucius acquisition. Overall, I'm proud to say we generated sufficient cash flow to fund CapEx, acquire accretive working interests, pay our quarterly dividend, reduce $248 million of debt, and still add cash to the balance sheet. Slide seven. During the third quarter, we executed a variety of de-levering transactions. With the debt reduction earlier this year, combined with the $200 million redemption announced earlier this week, we are on track to achieve the high end of our debt reduction goal of $650 million by 2022. Looking back to the end of 2020, in addition to our senior notes, we had a balance of approximately $200 million on our revolver. However, our de-levering efforts over the past two years have significantly strengthened the balance sheet. By the end of this year, we are forecasting total debt reduction of $1.2 billion over those two years, with $1.8 billion remaining comprised of long-term senior notes. We will have achieved this reduction while increasing oil production and dividends this year. With that, I'll turn it back over to Roger to expand on our production for the year. Thanks, Tom. On slide eight, we continue to see immediate positive results from our decision earlier this year to enhance our onshore well completion designs as production remains above expectations. Additionally, as previously mentioned, the new wells at Khaleesi, Mormont and Samurai are producing above expectations. Overall, our total oil production is forecast to increase 30% from the first to the fourth quarter of this year. For the fourth quarter, we forecast production of 173.5-181.5 thousand barrels equivalent per day, with 55% oil and 62% liquids. Total production volumes are impacted by 10,000 barrel equivalents per day for forecasted Tupper Montney royalty changes. 9,500 of the oil equivalent per day is from offshore downtime, including 1,600 barrels oil equivalent per day for downstream weather impacts associated with Hurricane Ian. 4,500 barrels a day for underperformance of the non-operated Kodiak 3 well. However, it's important to note that the performance at Khaleesi, Mormont, and Samurai offset most of these impacts. For full year 2022 guidance, we're revising back to our original range of 164,000-172,000 barrels equivalent per day, with 54% oil and 60% liquids. While this is primarily due to royalty increases at Tupper-Montney, I'm pleased to say that our full year forecasted oil volumes are 4,000 barrels of oil per day higher than our original guidance in January and has no change from the August guidance provided. As to capital allocation on slide nine, today I'm excited to describe some great opportunities that Murphy's to take advantage of. These projects lead to a revision in our 2022 CapEx guidance with a new range of $975 million-$1.025 billion, excluding acquisitions. Of this $75 million revision, $40 million is attributed to high return Gulf of Mexico projects, including the addition of the new Samurai 5 well, allowing us to build on the success of that field. This well is one of the most highly economic opportunities I've seen in my entire career. Allows us to utilize below-market rig rates in a tight rig supply environment in the Gulf of Mexico. Additionally, $20 million is to support further work in the Eagle Ford Shale, primarily non-operated activity following success of nearby wells. Ultimately, the majority of this capital will bolster operations through production and cash flow generation, leading to higher returns as we transition into 2023. For a continued update, I'll now turn the call over to Eric, our EVP of operations. Thank you, Roger, and good morning, everyone. Slide 11. Our Eagle Ford Shale assets produced 39,000 barrels of oil equivalent per day with 87% liquids, which was 6% above guidance. We brought online four operated wells in Catarina as planned, as well as three non-operated Tilden wells. Our wells continue to exceed initial forecasts after revising our completions method in early 2022, and we're achieving some of the highest per foot IP30 rates in Murphy's history. While the results are still early for our third quarter Catarina wells, in particular for the two Austin Chalk wells, initial indications point to de-risking of up to 100 Austin Chalk wells locations in this area. The team has also done a tremendous job at managing existing wells, and our base production decline remains steady at 11% for pre-2022 wells. Slide 12. Murphy produced a net 376 million cu ft per day in the third quarter from the Tupper Montney, or 395 million cu ft per day on a gross basis. Five wells came online early in the quarter, which completed our program for the year. Overall, we achieved our 2022 program for $4.8 million per well, which was only 10% higher than our 2021 program. Most significantly, we achieved a record high gross production peak of 415 million cu ft per day in the quarter, showcasing the capability of this asset. This continued strong performance is due to the longer laterals we announced in the first quarter as part of our scope changes for the asset. However, while we are very pleased with the payout of these wells at an average of six months, higher natural gas prices triggered higher royalty rates earlier than we forecast. On slide 13, Tupper Montney royalties are expected to increase significantly in the fourth quarter of 2022, leading to a nearly 11,000 barrel of oil equivalent per day impact. Tupper Montney royalties are determined by a sliding scale percentage that is driven by natural gas prices and are partially offset by royalty credits that are specific to each well. New wells pay a minimum royalty amount until the royalty credits are consumed, then begin paying royalties based on the sliding scale. The natural gas price used to determine the royalty amount is known as the Posted Minimum Price and is published by the British Columbia government about three months after the month in which it was realized. Since future Posted Minimum Prices are not known, we forecast future royalties by correlating the historical relationship between AECO prices and the Posted Minimum Price, and then apply that correlation to the AECO forward curve. During 2022, we have seen higher Posted Minimum Prices than expected due to a shifting correlation between AECO prices and the Posted Minimum Price. The higher prices, combined with our strong well results, consume royalty credits much quicker than predicted, resulting in a sudden and large increase in royalties much earlier than originally predicted. Looking to 2023, our overall royalty rate will remain relatively high, along with elevated natural gas prices. If prices remain elevated in 2023, we expect royalties in the 20% range, which is significantly higher than the 3%-6% historically observed. It is worth noting that our free cash flow generation is driven primarily by our oil-weighted assets in the Gulf of Mexico and the Eagle Ford Shale, so the lower Tupper Montney net production will not significantly impact our capital allocation framework or our ability to reduce debt. Slide 15. Our Gulf of Mexico operations produced 76,000 barrels of oil equivalent per day in the third quarter, with 80% oil volumes, which exceeded guidance as we were fortunate that hurricanes did not approach our assets. Spud during the quarter, we have since reached total depth at Dalmatian 1. We anticipate the successful well to come online in 2023. We also participated in drilling two non-op subsea tieback wells at Lucius with completions ongoing and closed the highly accretive acquisition of additional working interest at Lucius. I mentioned last quarter that our operating partner would be drilling the Kodiak 3 well. Unfortunately, the well has performed below expectations and work plans are being developed by the operator for remediation. Slide 16. The Khaleesi, Mormont, and Samurai field development project and the Murphy-operated King's Quay floating production system has been a tremendous success for the company since achieving first oil in April. We recently brought online the first well from the Samurai field with the previous five wells initiating production throughout this year from the Khaleesi and Mormont fields. The team is continuing completions on the remaining Samurai well, and this will close out the initial seven-well development program. Production continues to exceed expectations with current total gross production of 120,000 barrels of oil equivalent per day, net production of 32,000 barrels of oil equivalent per day, and a high oil cut of 85%. Khaleesi and Mormont has been an incredible field for us this year as we go into 2023, and high production rates are well above our original forecast when we purchased the asset in 2019. We're also very pleased with early production at the Samurai field that was originally discovered by our exploration team, and this field keeps getting better as Samurai's success has been greatly enhanced by the proximity of the Khaleesi and Mormont fields. Earlier this year, we disclosed the discovery of additional pay zones in the Samurai field during the initial phase of development. As a result, we have expanded our capital plan and drilling program for the year to include drilling the new Samurai 5 well in the fourth quarter. Overall, we forecast production to plateau across the three fields for the next several years without additional development. With that, I will turn it back to Roger. Thank you, Eric. We'll talk about exploration now on slide 18. Exploration remains the third pillar of our strategy, and Murphy's held a 40% operated working interest in Block 5 in the Salina Basin in offshore Mexico for several years. Looking forward to spudding the Tulum exploration well later this month with a net cost of approximately $23 million. Located in the lower Miocene fairway on the western side of Block 5, we anticipate this well to have a mean to upside gross resource potential of 150-350 million barrels equivalent. Murphy's identified multiple follow-on opportunities in the area that could be de-risked following results of Tulum. Further on slide 19, we're excited to report that Ridgewood and Oxy, through its Gulf of Mexico subsidiary Anadarko, entered into an agreement with Murphy to participate in our Oso exploration well in the Gulf of Mexico. We remain the operator preparing to spud the well late in the fourth quarter, with drilling anticipated to continue into the first quarter of 2023. This well has a similar estimated mean unrisked gross resource potential of 155 million- 325 million barrels equivalent, and is forecast to cost approximately $22 million net to Murphy. Success can lead to extensive value creation, and we've seen that the results from exploration discoveries of Dalmatian and Samurai, both incredible fields for us today. I'm pleased that we're about to spud two key wells in the quarter with a similar size and risk component with great partners. As we turn to slide 21, as originally announced this quarter, we have a multi-tier capital allocation framework that allows for additional shareholder returns beyond the quarterly dividend base of $0.25 per share, while advancing toward our long-term debt range of $1 billion. Additionally, we maintain a board authorized initial $300 million share repurchase program, allowing Murphy to repurchase shares through a variety of methods with no time limit. As of today, we've not yet executed any repurchases under that authorization. On slide 22, in summary today, I'm so proud of our offshore business. It gives Murphy a competitive advantage. Khaleesi, Mormont and Samurai fields projects flowing to King's Quay is a significant project adding to our longevity and illustrates our key abilities in industry-leading offshore execution, as well as accretive A&D, having acquired Khaleesi, Mormont in 2019. These fields are home run balls for us, and will set the tone for the year, and have built production and cash flow going into 2023. This incredible execution, coupled with production exceeding expectation across all of our oil-weighted assets, including the Eagle Ford Shale, has led to significant free cash flow generation, enabling Murphy to achieve its debt reduction goal by the end of 2022, increase our dividend, and advance our capital allocation framework. We're preparing to spud two operated exploration wells later this month with Tulum in offshore Mexico and also Oso in the Gulf, and I'm looking forward to kicking off 2023 with these key results. As I said earlier, we're proud and excited to increase our capital spending in our two highly economic key oil-weighted assets, as we simply could not pass these accretive projects up at these prices. In closing, I want to thank our employees for their tremendous effort this year in executing our significant project with huge success, supporting our base production, and help us achieve our strategic priorities. I'm pleased to say that we're well positioned for the future as we close out 2022, and it wouldn't be possible without our team's accomplishments. I'm now going to turn the call back over to the operator for your questions this morning. Thank you. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star key followed by the number one on your touch-tone phone. You'll hear a three-tone prompt acknowledging your request. Questions will be taken in the order they are received. Should you wish to withdraw your request, please press the star key followed by the number two. If you're using a speakerphone, please lift up your handset before pressing any keys. One moment while we assemble the queue. We'll take our first question from Neal Dingmann with Truist Securities. Your line's open. Thanks for the time this morning, Roger. It seems, let's get right to it. The market seems to me this morning is not appreciating your upcoming activity. Really my first question is on your planned well activity. Maybe specifically, could you give maybe your early thoughts on how you view the upcoming Gulf of Mexico wells, including your thoughts on bringing that Oso well forward? Thanks. I'll let Eric take care of the Samurai. I'll add additional color on that and handle Oso. Go ahead, Eric. Okay. Yeah. Thanks, Neal. It's a good question on our program offshore. The Samurai 5 well, as we highlighted in our prepared comments, is driven by the early development phase of the field. We discovered a number of additional reservoirs or additional pay sands, and a couple of them look really, really large and attractive and high quality. It's a compelling investment for us to add an additional well to develop those sands. You can imagine that super high capital efficiency to develop a field in an existing field development with existing infrastructure. We're also advantaged, as Roger tried to highlight, that we're able to execute that work with a rig that we're using and has a below-market rig rate right now. Overall, capital efficiency of the well is expected to be super high. It'll be one of our highest rate of return investments. It'll also allow us to provide stability to our offshore business. We've highlighted in previous calls that we're targeting maintaining an overall flat offshore oil business for the next four, five, six years, and this well will go a long way toward accomplishing that. We're really excited about adding this well into the program. The small additional capital increase in 2022 will support nice, strong free cash flows from 2023 and beyond. We really think it's a great opportunity for us. Neal, I'm going to add a little more color there. What you got to realize in the offshore business that there's only 13 rigs that work in the Gulf. We have a rig provided to us today by Noble Corporation working at our Khaleesi, Mormont and Samurai field. We just completed a 30,000-foot completion with five hours, Neal, five hours of non-productive time. To let that rig go, not know when it can come back at half the market rate, one could never pass up the opportunity to develop that work and add to the capital at this time because the rig is working so well and we're doing so well out there in the field. That comes and goes differently in offshore than it does onshore. On top of that, there's additional capital in Eagle Ford, where we participate in some non-operated wells. They went extremely well. Then we were AFE'd to do more, and I just can't see passing up those types of returns. As to the OSO well, it's a very nice opportunity for us, something we're homegrown here, we're quite proud of. We have had 50% working interest there, but we wanted to go down to a typical 30%-40% level that we've done in the past. Oxy is a great partner and is back to business in the Gulf. We're doing a lot of great work with Oxy at Lucius. They wanted to enter our well. They also bring their own set of seismic information, allows for another look at the technology around seismic for the project, which is helpful. We're glad to have them. It's a real nice well for us and a place where we can really showcase our unique development opportunities and bring oil forward. What we do, as you know, Neal, is bring things forward quicker, better, on time, on budget, and we're just as excited as we can be to drill a well with them, a new partner, and of course, Ridgewood, who's our partner at Khaleesi and Mormont. All in all, just a great situation for us. I'm real proud and excited about this CapEx, Neal, and I think it's the right thing to do for the company. I really do. Yeah, I would agree with you. I hope the market better appreciates and understands it. My second is just maybe around the three fields. You guys did give a great color on this, but hoping for maybe even a little more color on the three fields around King's Quay. I'm just wondering, could you speak to really the production now, how you anticipate that production trending in the coming quarter? Will that, you know, stay up quite well? Could you talk potentially about other opportunities in 2023, 2024 in the three fields? Yeah, Neil, let me provide a little bit of color for you on the mixed production in King's Quay. As we highlighted earlier, our Khaleesi and Mormont fields came online earlier and are producing the bulk of the production from the field so far this year. We brought online the Samurai well recently, and it's doing very well. As we highlighted, we will soon bring on the seventh well in the program, the Samurai 4 well in the coming weeks. As we add that well into the production mix to the facility, what we expect to see is that the total gross production should remain approximately where it is right now. Again, that's about 120,000 barrels of oil equivalent per day on a gross basis, about 85% oil. We'll add additional wells, bring on additional volumes, but then we'll have to reduce the production rate from the Khaleesi and Mormont fields to allow for additional production at Samurai. The Samurai wells will benefit us a bit because we have a higher working interest at 50% in the Samurai wells compared to 34% in the Khaleesi and Mormont wells. You may see a slight uptick in net production, but again, we should expect the total production rate to be somewhat similar to what it is now. We're really happy with the execution we have there. The overall three-field development is producing way above our initial expectations. We expect that with the wells that we described here, that we will remain on a production plateau from the three fields for about three years without additional development. We will continue to evaluate additional opportunities for future wells in the Khaleesi, Mormont and Samurai field development area. We, as normal, will monitor the performance of the fields and evaluate where there may be opportunities for additional wells. We don't have any firm plans around those right now, but as we experience the production and can do some additional modeling, we will likely develop some future opportunities that will help extend the plateau beyond the approximately three years that we're forecasting right now. Great, guys. Look forward to all the activity. Thanks, Neal. Appreciate it. As a reminder, if you have a question, it's star one on your cell phone keypad. Next, we'll go to Leo Mariani with MKM. Your line is now open. Good morning, Leo. Hey, morning. I wanted to follow up a little bit on the Montney, Tupper Montney royalty issue here. Maybe you guys could help us out a little bit and put like some prices around this. You're expecting to lose 10.5 MMBOE per day here in the quarter. Was there certainly like a certain price level on AECO that kind of triggered this? And you also mentioned in your prepared comments that if gas prices were to stay elevated in 2023, you could pay a 20% royalty rate. How does that 20% compare to what you're paying you know in the fourth quarter? And what type of prices would sort of get you to the 20% next year? Just trying to kind of calibrate around this a little bit, as we watch prices be very volatile. Okay. Thanks, Leo. Let me try to kind of frame that for you. The situation that we have in 2022 is that we have experienced throughout the second through third quarters and then expected into the fourth quarter significantly higher Posted Minimum Prices, which is what the price is used to determine royalty. The reason that we're seeing higher Posted Minimum Prices is that the historical correlation between AECO and Posted Minimum Price changed significantly through the year. As we're building our budgets and our long-range plans, we forecast AECO prices based on a forward curve, a strip, whatever. That hadn't changed too much. We saw slightly higher AECO than we expected, but the Posted Minimum Price relative to AECO really changed and almost collapsed to be nearly the same number. That impact of that throughout the last few months and expected into the fourth quarter is that we chewed through royalty credits, what are called deep well royalty credits, significantly faster than we expected. The reason that's material for our fourth quarter is new wells start out with a 3% royalty. Until that's a minimum royalty they have to pay while they still have remaining unconsumed deep well royalty credits. When the royalty credit is consumed, those wells will jump from a 3% minimum to something driven by the natural gas price. At the prices we're seeing lately above CAD 3.50, then that percentage is 27% royalty. You have a jump from 3%- 27% very rapidly on a number of really nice high rate wells. The overall weighting of a high volume, 27% royalty versus 3% just in the months prior really drives the royalty up. If you look at our slide 13, you can see for the fourth quarter, we're expecting AECO of CAD 5.65, and that would translate to an estimated 17% average weighted royalty for the quarter. As we move into 2023, we expect a similar kind of price level, but we'll have additional wells roll off their royalty credits, and so we think that the average royalty will creep up into the, say, 20% range. Just a couple of things to highlight. First, in terms of next year, we're still working on our program. We haven't detailed our 2023 plans, but the new wells in British Columbia will benefit from an enhanced royalty structure. They start with a higher minimum royalty of 5%, but they're 5% for 12 months exactly. There'll be a lot less uncertainty about the royalty you're paying on those new high rate wells. That should really help us if we continue to see elevated natural gas prices, as we expect. The other thing I just wanted to circle back to was we do not expect that this lower production from Montney will significantly impact our free cash flows. Again, as I mentioned, our free cash flows are predominantly driven by our oil-weighted Eagle Ford and Gulf of Mexico assets. We put in place some fixed forward sales at relatively low prices as we committed to a multi-year expansion project in the Montney. We would love to have higher prices there, but because we have forecast them as always being a little bit low, the free cash flow was a bit muted from the asset. It'll continue to be a bit muted from the asset. Because we knew that was happening, it just really doesn't affect our capital allocation framework, our ability to pay down debt or generate material free cash flow from the rest of our assets. Okay. That was great color. Maybe just to follow up quickly on that point, you talked about, you know, kind of mid-five CAD AECO next year in terms of the forecast. I'm just curious, if gas were to be, say, a lot lower, say, AECO is CAD 3 next year, could there be a lot of downside to that 20%-ish type royalty? Or I'm sure there's probably some time lag there as well. Just trying to get some sensitivities kind of around how that may play out. Yeah. If you have natural gas prices AECO below CAD 3, the royalty rate will fall very rapidly. It would be an upside for us on a volume basis. Okay, that's helpful. I also wanted to ask on the downtime in the fourth quarter. You guys talked about kind of 9.5 million barrels in the offshore. Can you give us a little bit more color around that? Is that something that's pretty transitory? Do you expect all that to come back online here maybe early in 2023? Just any thoughts there? Yeah, sure. Let me give you a little bit of detail on that. Early in the quarter, in quarter four, we experienced some downtime at a number of facilities. Most of the downtime for operated facilities and non-operated facilities offshore is sort of behind us. We highlighted 1,600 barrels of weather impact, which is early in the quarter, and of course, we don't expect additional weather impacts. One of our key operated fields had significant downtime related to equipment repair. That problem has been resolved, and the field is producing at nearly normal rates and expect to be fully normal rate very soon. Then in our non-operated business, we had about 1,100 barrels of downtime projected for the quarter, and that was almost entirely driven by Hibernia, which had a slightly longer maintenance campaign early in the quarter than expected. That problem is resolved. The field is producing at normal rates. If you just sort of look at the overall pluses and minuses on production for the quarter, we have really nice performance from Eagle Ford, which we've highlighted, which improved our expectations for fourth quarter production. We have Khaleesi, Mormont and Samurai wells adding 5,700 barrels more production in the fourth quarter than we expected based on really strong results. The rest of our offshore business, we expect to be up nearly 3,000 BOE a day just on nice, strong performance. Those help offset the downtime events that we talked about. The Kodiak 3 well, which we highlighted, is underperforming about 5,400 barrels a day. That's kind of what gives you a bit of color around the pluses and minuses for the quarter. Okay. Great color on the numbers. It sounds like most of that $9,500 you guys would expect to be back on early next year here. That's right. Yes. Should be back online. Some of it's already back online, and a lot of it ought to be back online very soon in this quarter. Yes. Okay. Thank you, guys. See you. Okay. Next we'll go to Paul Cheng with Scotiabank. Your line is now open. Hey, guys. Good morning. I know you're still early on, but I think before today or then in the last call, you sort of had $750 million or so for next year CapEx with everything going on with the higher inflation and also it seems like you are accelerating some activities. Can you give us some idea of all the different moving parts on the CapEx for next year and how that may shake up? Also, I think previously you've been targeting a production somewhere in the 200-220 for next year and moving forward for the next decade, with the royalties way higher than many. Should we just assume that will be shipped down by somewhere in the 10,000-15,000 barrels per day? Thank you. Thanks, Paul, for your question this morning. Appreciate that. I'm not surprised to have a 2023 CapEx call and no issue at all with that. I can understand that. As you know, we're not able to provide specifics today on our 2023 budget because our board hasn't approved this yet. We're working on it, and we'll be announcing this, along with many other peers on our fourth quarter earnings call in late January. I'm not gonna give the specifics on your capital question, Paul, but I can pass on today our preliminary thoughts. We're looking to maintain our prior plan as to scope of work in our onshore business. We're reviewing ongoing inflationary pressures that are primarily related to our onshore business. We're also reviewing additional scope with our Gulf of Mexico, two of which we talk about today. We're obviously drilling a Samurai well that will cross into 2023, and will need to be completed and tied in with just a small jumper to our ongoing facility. We also announced today, it hasn't been discussed much, that we drilled a very nice successful development well at Dalmatian. That well will need to be completed as well. We're reviewing our Tupper Montney calculations, and I'll talk about that in a minute. As we just said from the previous call with Leo, if you're around CAD 5-CAD 5.50 AECO for next year's Canadian dollar, that would be a 20% royalty, which is higher than we had in the past. Our capital 2023 will for sure be less than 2022, Paul, for sure. Our oil production will be higher, and we're gonna be announcing those numbers here soon. As to your long-term question on production, the way we're looking at it today, and we're still in the middle of our long range plan, is that while that 200-220 is still a very viable answer going forward, I would anticipate that next year would be lower due to Montney royalty at 20% that wasn't in projected. Longer term, in AECO Gas, we do not have these higher prices, which will get us back to the range that we've always discussed. I've reviewed that closely this week. We see this as a 2023 issue. If it were to go further though, Paul, and have lower production with our forward sales coming off that were put on board to handle our execution, we'd have enormous positive free cash flow. While Eric said earlier that the Montney doesn't impact our immediate free cash flow or capital allocation frameworks, it is set up to be a solid $200 million per year free cash flow business from 2024 onward as we fill that plant next year. None of those plans have changed. We do not anticipate AECO being at that level long term. If it is, it'll be an incredible home run ball for us, doubling the free cash flow that I just mentioned. If it comes back in line, we'll be back to just as the numbers we discussed here the last couple of months. I think that answers your question, Paul. If not, just ask me. Yeah. Roger, I understand that it's probably too early to get any granular on the budget. Just curious then, what is the inflation rate that you guys are seeing or that you are planning at this point for next year? Eric's gonna be my inflation man this morning, Paul, for you. He's greatly prepared. Okay, Paul. Obviously, for our business, most of the pressure we're seeing is in our onshore business. As we head into 2023, we're seeing cost pressures in drilling rig rates, casing, pressure pumping costs. Obviously, we're still working our budget and for finalizing our plans to present to our board for approval. We recognize that we're seeing those cost pressures. What we're anticipating to do in response is to increase the lateral lengths of our wells, both in the Tupper Montney and the Eagle Ford Shale. We might see per well costs increase in 2023 from 2022 levels by, say, 10%-25%. Maybe 10%-15% in the Montney, maybe 20%-25% in the Eagle Ford. In those assets, we intend to increase our lateral lengths even more than those per well costs. Maybe Tupper would be around 20% longer wells. On a cost per lateral foot basis, we'll actually see a reduction in well cost, if that makes sense. In our offshore business, the primary area where we see cost growth in our offshore business is in rig rates. We are fortunate that we have secured some, what is currently below market pricing for more than half of our year of offshore activity next year. Beyond that, we'll see rig rates approach current markets. Rig rates in the market right now are in the ballpark of 40% higher than what we've been executing on recently and in the first half of next year. Our contracting and our work plans and the things we've locked in for our offshore business really mute the inflationary impact to our offshore business next year. Hopefully that helped kind of frame where we're seeing changes for you. Yeah. It does. Thank you. Roger, a final question. One of your peers just announced a bolt-on acquisition in Eagle Ford, which is way out of your domain. Can you discuss about, say, the opportunity set and why so far that you may not be interested, given we have seen two deals from your peers recently? Oh, thanks, Paul, for that question. As we said earlier, and I've told you, and as you know, we feel we have a competitive advantage offshore because there are really people coming to us. With the lack of competition due to our execution ability and the ability to make one plus one three. I mean, that's what we've done in all of our M&A and offshore. As to the Eagle Ford area, Paul, we're an oil-weighted player there. This asset is not that at all. We have years of oil-weighted inventory. As you know, we're holding our production at 30-35 and making a lot of free cash flow there, especially at any kind of price of the eight handle. We feel that the locations we have are better than gassy condensate locations. If we were to purchase something like that and not invest in it over our oil-weighted assets, it would become almost investing as a PDP, and that's too much money to pay for that in that type of environment for us. Not to mention the price of this. What I'm really enjoying about it, Paul, is we're executing there at a very high level. I don't want people to believe it's just about offshore. Our Eagle Ford team's doing tremendous work too, and we love to see the super major, partners and peers buying very expensive Eagle Ford right around me, in my zip code. I really like that a lot. It means our company's undervalued, and 'cause I think we can compete with that level of value as well as any time. we like to see people paying a lot where we work, Paul, and that's kind of how we feel about it. Thank you. Thank you, Paul. Okay. Next we'll go to Charles Meade with Johnson Rice. Your line is now open. Hey, Charles. Good morning. Yes. Good morning, Roger, to you and your whole team there. I wanted to ask about the Gulf of Mexico and really King's Quay. It looks you know you guys mentioned in your press release that you're seeing oil rates 20% over what you guys had projected. I'm wondering if you could talk about how that facility's performing. I recognize a lot of times facilities can perform over nameplate, but how that facility's performing, particularly with respect to this Samurai 2 Well, which you know evidently was not in the original plan and will be additive to the oil rate that you guys expected there it seems. I'll try to address your question there. We highlighted in our release and some of our comments earlier that we're producing at 120,000 gross BOE per day on a equivalent basis, and that is about 100,000 barrels of oil a day. That rate is significantly higher than the expected rate we thought the facility could process before we brought it online. We are very proud of our team's performance and execution. We're seeing extremely high uptime at 96% uptime in the quarter, which we think is industry leading. We expect that the future production rates from the field will be in about that level on a growth basis for the foreseeable future, including up to the next, say, three years. As we bring online additional Samurai wells, the Samurai 4, which will come online in the fourth quarter, and the Samurai 5 well, which will come online in the second quarter of 2023, we will displace existing production into those fields. It'll slightly increase our production on a net basis, because we have a higher working interest in the Samurai than in the other fields. If you think about how you would kind of model us there, once we bring online the third Samurai well in the second quarter of 2023, we ought to have a pretty stable business and, again, a total gross production quite similar to what we're experiencing right now. The Samurai wells, the Samurai well that's on right now has produced in the 8,000-10,000 barrels a day gross range. Future wells will, in Samurai, we believe, have the production contribution from Samurai getting to about 25,000 barrels a day gross. Yeah. Charles, just to close that out, Charles, we've got six wells making 120,000 barrels a day. Yeah. I think that's pretty good. It's quite stout. If I have the right sense of it, these what it means, your success there is you're going to be at that, you know, max gross rate for longer, and your net is gonna nudge up a little bit because of the higher working interest. Is that the right understanding? That is exactly right. Yes. Okay. Thank you. I wondered if you guys talk about your drilling at Tulum well, or are you gonna spud it in 4Q. Can you set expectations for us on the timeline that we should be thinking about for when you spud, when you get to TD, and then when you'll be in a position to, you know, make some disclosures about what you guys find at TD? Okay. Thanks, Charles. Yeah, good question. Another thing to point out about our exploration, we're very excited about these two wells. You know, it's kind of unique to have two wells that cost the same amount of money and deliver about the same amount of reserves being drilled simultaneously. You know, and our net reserves from that would be incredible increase to our proven, which gives Murphy, you know, a unique perspective in investing with us. The way to think about it, what's key about it, we're operated now, and you go through phases of exploration where we're now entering an operated phase where we control our permits, unlike the earlier well this year. We control the CapEx. We control the timing. The rig that drilled a very successful well at Dalmatian over the last couple weeks, which we operate, of course. We're moving that rig to Mexico with our own team and spud our well here probably in two to three weeks. We think that's a 50-60 day well, and then we'll be picking up the other rig for Oso around Thanksgiving and taking that in there for about the same period. We have two wells that last 50-60 days, both operated by Murphy, both controlled by our team that's doing an incredible job drilling this year with rigs that we know and understand, and really happy about where we are, Charles. Roger, if things go according to schedule, which, you know, that's a big if, we could be looking at TD around 4Q reporting, maybe at the end of February. Is that the? Yep broadly the right way to think about it? Charles, you're ending on two exact statements, two questions in a row. That's correct. Thank you, guys. I appreciate the added detail. Appreciate it, Charles. Thank you. Okay. There are no further questions from our phone lines. I would now like to turn the call back over to Roger Jenkins for any closing remarks. Appreciate everyone calling in today. We had an incredible quarter, and all hands on deck to deliver another great quarter on our oil-weighted assets. Thanks everyone for calling in, and we'll see you in late January. Appreciate it. Ladies and gentlemen, this concludes today's conference call. We thank you for your participation. You may now disconnect.