Good morning everyone, and welcome to the Murphy Oil Corporation Third Quarter 2022 Earnings Conference Call. I would now like to hand it over to Kelly Whitley, Vice President of Investor Relations and Communications. Please proceed.

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 Mireles, Executive Vice President and Chief Financial Officer; and Eric Hambly, Executive Vice President of Operations. Please refer to the information on slides that 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 advantages reinforced with significant project success especially with the achievements of the Khaleesi, Mormont, Samurai field 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 3. 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 have 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 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 reserves in Eagle Ford Shale from our 2022 program and we're 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 entered into an agreement with Murphy to participate in the Oso well with Murphy remaining as operator and holding a 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 early 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 4. 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 tends to receive a premium to the WTI benchmark with NGLs just below $37 per barrel and nat gas was $4 per Mcf for Murphy. I'll now turn the call back over to our CFO, Tom Mireles for sustainability and financial update. Tom?

Thank you, Roger and good morning, everyone. Slide 5. 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 disclosures 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 6. 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 7. During the third quarter, we executed a variety of delevering 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 delevering 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 will turn it back over to Roger to expand on our production for the year.

Thanks, Tom. On slide 8, 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 173,500 to 181,500 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 for offshore downtime, including 1,600 barrels oil equivalent per day for downstream weather impacts associated with Hurricane Ian, and 4,500 barrels a day for the 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 to 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 of 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 9, today I'm excited to describe some great opportunities for Murphy to take advantage of. These projects lead to a revision in our 2022 CapEx guidance with a new range of $975 million to $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 and allows us to utilize below-market rig rates in a tight rig supply environment in the Gulf of Mexico. Additionally, $20 million to support further work in the Eagle Ford Shale primarily non-operated activity following the success of nearby wells. Ultimately, the majority of this capital will bolster operations through production and cash flow generation leading to high returns as we transition into 2023. For 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. 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 well locations in this area. The team has also done a tremendous job at managing existing wells and our base production decline remained steady, at 11% for pre-2022 wells. Slide 12, Murphy produced a net 376 million cubic feet per day in the third quarter from the Tupper Montney or 395 million cubic feet 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 cubic feet 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 barrels 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 shift in 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 sudden and large increased 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% to 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. During spud during the quarter we have since reached total depth at Dalmatian number one. 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 number three well. Unfortunately, the well has performed below expectations and work plans are being developed by the operator for remediation. Slide 16, the Khaleesi Mormont 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, 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 success has been greatly enhanced by the proximity of the Khaleesi, Mormont fields. Earlier this year, we disclosed the discovery of additional pay sands 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 number 5 well in the fourth quarter. Overall, we forecast production to plateau across the three fields for the next several years without additional development. And with that I will turn it back to Roger.

Thank you, Eric. And 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 upward gross resource potential of 150 million to 350 million barrels equivalent. Murphy has identified multiple follow-on opportunities in the area that could be derisked following results of Tulum. Further on Slide 19. We're excited to report that Ridgewood and Oxy through its Gulf of Mexico subsidiary Anadarko have 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 to upward growth resource potential of 155 million to 325 million barrels equivalent and is forecast to cost approximately $22 million net to Murphy. Success can lead to extensive value creation that we've seen at 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've maintained 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 that gives Murphy a competitive advantage. Khaleesi, Mormont, Samurai fields, projects flowing to King's Quay is a significant project, adding to our longevity and illustrates our key abilities and 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 expectations 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 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, and 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. And now, I'm going to turn the call back over to the operator for your questions this morning. Thank you.

Thank you. We will now begin the question-and-answer session. We'll take our first question from Neal Dingmann with Truist Securities. Your line is open.

Thanks for the time this morning, Roger. Let's get right to it. It seems the market isn't fully recognizing your upcoming activity. My first question is about your planned well activity. Could you share your initial thoughts on the upcoming Gulf of Mexico wells, particularly regarding the Oso well? Thanks.

I'll let Eric take care of the Samurai 5. I'll add additional color on that and handle Oso. Go ahead, Eric.

Okay. Yes. 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. A couple of them look really, really large and attractive and high quality. And it's a compelling investment for us to add an additional well to develop those sands. If you can imagine, that super high capital efficiency to develop a field and an existing field development with existing infrastructure and 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. So, overall capital efficiency of the well is expected to be super high. It will be one of our highest rate of return investments. It will 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. So 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. So we really think it's a great opportunity for us.

And Neal, I'm going to add a little more color there. What you got to realize in the offshore business 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 Samurai field. We just completed a 30,000-foot completion with five hours, Neal, five hours of nonproductive time. So, 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. So that comes and goes differently in offshore than it does onshore. And on top of that, there's additional capital in the Eagle Ford where we participate in some non-operated wells that went extremely well. And then we were AFE 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 that we've homegrown here we're quite proud of. And we have had 50% working interest there, but we wanted to go down to a typical 30 to 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 that 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. And we're glad to have them. It's a real nice well for us in 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 are just excited as we can be to drill a well with them a new partner, and of course, Ridgewood who's our partner at Khaleesi, Mormont. So, all-in-all, just a great situation for us. And I'm really proud and excited about this CapEx, Neal. And I think it's the right thing to do for the company I really do.

Yes, I would agree with you. I hope that the market better appreciates and understands that. My second is just maybe around the three fields. You guys did have a great color on this, but hoping for maybe even a little more color on 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 stay up quite well? And then could you talk potentially about other opportunities in 2023, 2024 in the three fields?

Yes. Neal, I can provide some details about the production mix at King's Quay. As we mentioned earlier, our Khaleesi and Mormont fields have begun producing and are currently responsible for most of the output this year. We recently brought the Samurai well online, and it's performing well. Soon, we will also bring the seventh well, Samurai number four, into production in the upcoming weeks. We anticipate that adding this well will keep total gross production roughly at the current level, which is about 120,000 barrels of oil equivalent per day, with around 85% being oil. While we will add more wells and volumes, we will have to decrease the production rate from the Khaleesi and Mormont fields to accommodate additional production from Samurai. The Samurai wells will slightly benefit us due to our higher working interest of 50%, compared to 34% in the Khaleesi and Mormont wells, resulting in a potential small increase in net production. However, we expect the overall production rate to be similar to what it is now. We are pleased with our execution, as the combined three-field development is exceeding our initial expectations. We believe we can maintain production at this plateau for about three years without further development, while we continue to explore opportunities for future wells in the Khaleesi, Mormont, and Samurai development area. We will monitor field performance and identify any opportunities for additional wells, although we don't have any concrete plans at this moment. As we analyze production and conduct further modeling, we may identify future opportunities that could extend the plateau beyond the three years we are currently forecasting.

Hi, good morning. I wanted to follow up on the Montney royalty situation. Could you provide some price context? You're anticipating a loss of 10.5 MMBOE per day this quarter. Was there a specific AECO price level that triggered this? Additionally, you mentioned that if gas prices remain high in 2023, you could pay a 20% royalty rate. How does that 20% compare to your fourth-quarter payments, and what prices would lead you to the 20% rate next year? I'm trying to understand this better as we observe the price volatility.

Thank you, Leo. Let me clarify that for you. In 2022, we noticed during the second and third quarters, and we anticipate continuing into the fourth quarter, a substantial increase in the posted minimum prices, which are used to calculate royalties. This rise in posted minimum prices stems from a significant change in the historical correlation between AECO and the posted minimum price throughout the year. As we prepare our budgets and long-term plans, we forecast AECO prices based on forward market trends, and this expectation has not shifted much. We observed slightly higher AECO prices than anticipated, but the relationship between posted minimum prices and AECO has changed dramatically, nearly aligning them. This alteration has led us to consume deep well royalty credits much faster than we projected. This is particularly important for the fourth quarter because new wells start with a 3% royalty, the minimum they must pay while they still have unused deep well royalty credits. Once those credits are depleted, the wells' royalty percentage will increase based on natural gas prices. With current prices above CAD 3.5, the royalty rate jumps to 27%. Consequently, the shift from 3% to 27% occurs quickly with several high-rate wells. The added weight of these high-volume wells at a 27% royalty rate, compared to the previous 3% rate, significantly raises the average royalty. For the fourth quarter, we are anticipating an AECO price of CAD 5.65, which would result in an estimated average weighted royalty of 17% for the quarter. As we transition into 2023, we expect prices to remain similar, but more wells will come off their royalty credits, leading us to believe that the average royalty will rise to around 20%. A couple of points to note for next year: we are still refining our plans, but new wells in British Columbia will benefit from an improved royalty structure, starting at a minimum of 5% for the first year. This will reduce uncertainty regarding royalties on those high-rate wells. This should benefit us if natural gas prices remain high as anticipated. Additionally, I want to reiterate that we do not expect the reduced production from Montney to significantly impact our free cash flows. Our free cash flows are primarily influenced by our oil-heavy Eagle Ford and Gulf of Mexico assets. We have secured some fixed forward sales at relatively low prices due to a long-term expansion project in Montney. Higher prices there would be advantageous, but since we projected them conservatively, our free cash flow from that asset may remain limited. Nevertheless, this situation has been anticipated and does not impact our capital allocation strategy, our capacity to reduce debt, or generate significant free cash flow from our other assets.

Okay. That was great color. And maybe just to follow up quickly on that point. You talked about kind of mid-5s AECO next year in terms of the forecast. I'm just curious if gas were to be, say, a lot lower, say AECO's $3 next year, could there be a lot of downside to that 20%-ish type royalty, or as I'm sure there's probably some time lag there as well? I'm just trying to get some sensitivities kind of around how that may play out.

Yes. If you have natural gas prices at AECO below CAD 3, the royalty rate will fall very rapidly. So it would be upside for us on a volume basis. Yes, sure. Let me give you a little bit of detail on that. So 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’s producing at nearly normal rates and expect it to be fully normal rate very soon. And 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. And that problem is resolved. The field is producing at normal rates. So 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, 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. And those help offset the downtime events that we talked about. And then the Kodiak 3 well which we highlighted is underperforming about 5,400 barrels a day. That kind of what gives you a bit of color around the pluses and minuses for the quarter.

Okay. Great. Great color on the numbers. So it sounds like most of that 9,500 you guys would expect to be back on early next year here.

It should be back online. Some of it is already back online, and a lot of it is expected to be back online very soon this quarter.

Good morning, everyone. I understand you are still in the early stages. I recall that during the last call, you mentioned a capital expenditure estimate of around $750 million for next year. Considering the current inflationary pressures and the various activities being shared, could you provide some insights into the different factors affecting next year's capital expenditures and how they might change? Additionally, I remember you targeting production levels between 200,000 and 220,000 barrels for next year and beyond. With the royalty structure at Montney becoming more burdensome, should we anticipate a downward adjustment of approximately 10,000 to 15,000 barrels per day? Thank you.

Thanks, Paul for your question this morning. I appreciate them. 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 in our fourth quarter earnings call in late January. I'm not going to 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 the 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 but 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. So 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 $5 to $5.50 AECO for next year's C dollar that would be a 20% royalty which is higher than we had in the past. So our capital 2023 will for sure be less than 2022 Paul, for sure. And our oil production will be higher. And we're going to 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 to 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 projected. And then 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. And I 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 would have enormous positive free cash flow. And while Eric said earlier that the Montney doesn't impact our immediate free cash flow or capital allocation framework, 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. So none of those plans have changed. We do not anticipate AECO being at that level long-term. If it is, it will 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 in the last couple of months. I think that answers your question Paul. It's not just...

I understand that it's probably too early to get any granular on the budget. But just curious what is the inflation rate that you guys are seeing or that you are planning at this point for next year?

Eric is going to be my inflation man this morning Paul for you. He's greatly prepared.

Okay. Paul, for our business, most of the pressure is coming from our onshore operations. As we enter 2023, we are facing cost pressures related to drilling rig rates, casing, and pressure pumping costs. We are still finalizing our budget and plans to present to our Board for approval. We acknowledge these cost pressures and, in response, we plan to increase the lateral lengths of our wells in both the Tupper Montney and the Eagle Ford Shale. Therefore, we expect per well costs to rise in 2023 compared to 2022 levels by about 10% to 25%, with an increase of approximately 10% to 15% in the Montney and 20% to 25% in the Eagle Ford. However, we intend to lengthen our wells significantly beyond these cost increases; for instance, Tupper could see wells about 20% longer. As a result, on a cost per lateral foot basis, we anticipate a reduction in well costs. In our offshore segment, the main area where we observe cost growth is in rig rates. Fortunately, we have secured contracts at below market pricing for more than half of our offshore activities next year. After that, rig rates are likely to align more closely with current market levels, which are approximately 40% higher than the rates we’ve been executing recently, especially in the first half of next year. Our contracts and work plans help mitigate the inflationary impact on our offshore business for the upcoming year. I hope this gives you a clearer picture of where we are seeing changes.

It does. Thank you. And Roger, for your final question, one of your peers just announced a bolt-on acquisition in Eagle Ford. Can you discuss the opportunity set and explain why you may not be interested, especially considering we have seen two deals from your peers recently?

Thank you for the question. As we mentioned earlier, we believe we have a competitive advantage offshore due to our execution capabilities and our ability to create significant value. This has been evident in all our mergers and acquisitions in the offshore sector. Regarding the Eagle Ford area, we focus on oil production there, while this particular asset does not align with that strategy. We have a substantial inventory of oil-weighted opportunities. As you know, we're maintaining our production levels between 30% to 35%, generating significant free cash flow, particularly at any positive price point. We see our available locations as superior to gas condensate ones. If we were to acquire assets that don’t align with our oil-focused strategy, it would effectively mean investing in something less valuable, which is not financially prudent for us, especially given the current pricing environment. I also want to emphasize that our execution in the Eagle Ford is performing exceptionally well. It's not just about our offshore operations; our Eagle Ford team is doing outstanding work. We take note of the major players and competitors purchasing high-value properties nearby, which suggests our own company is undervalued. We believe we can compete at that level of valuation whenever necessary. We appreciate seeing others willing to pay high prices in our area. That's our perspective on the situation.

Good morning, Roger, and your entire team. I wanted to ask about the Gulf of Mexico, specifically regarding King's Quay. You mentioned in your press release that oil rates are 20% above your original projections. Could you provide insights on how that facility is performing? I understand that facilities can often exceed their nameplate capacity, but I'm particularly interested in the performance related to the Samurai-2 well, which wasn't part of the initial plan and seems to contribute to the anticipated oil rate.

I'll address your question. We pointed out in our release and earlier comments that our production is currently at 120,000 gross BOE per day, which is approximately 100,000 barrels of oil each day. This figure is considerably higher than what we anticipated the facility could handle before it went online. We're very proud of our team's performance and execution, achieving an impressive uptime of 96% in the quarter, which we believe is leading in the industry. We expect future production rates from the field to remain around this level on a gross basis for the foreseeable future, particularly over the next three years, as we bring additional Samurai wells online, including Samurai-4 in the fourth quarter and Samurai-5 in the second quarter of 2023. We will shift existing production to these fields, which will slightly boost our net production due to our higher working interest in the Samurai fields compared to others. Once the third Samurai well is operational in the second quarter of 2023, we anticipate a stable business model and total gross production to remain similar to current levels. The Samurai well that is currently operating has been producing between 8,000 and 10,000 barrels a day gross, and we believe future wells in Samurai will increase that production contribution to about 25,000 barrels a day gross.

Yes. Just to close that out Charles, we've got six wells making 120,000 barrels a day. I think that's pretty good.

Okay. Thanks Charles. Yes.

There are no further questions from our phone lines. I’d now like to turn the call back over to Roger Jenkins for any closing remarks.

I appreciate everyone calling in today. We had an incredible quarter and all hands on deck to deliver another great quarter in our oil-weighted assets. And thanks everyone for calling in and we'll see you in late January. I appreciate it.

Ladies and gentlemen, this concludes today's conference call. We thank you for your participation. You may now disconnect.