Hello, my name is Sarah, and I will be your conference operator today. All lines have been placed on mute to prevent any background noise. After the presentation, there will be a question-and-answer session. If you would like to ask a question during this time, simply press star followed by the number one on your telephone keypad. If you would like to withdraw your question, please press star one again. Thank you. I will now turn it over to Atif Riaz, Vice President, Investor Relations & Treasurer. Thank you, operator. Good morning, and welcome to Murphy's three-part educational webinar series. This series has been designed to highlight the company's exploration and development strategy with a specific focus on our growing Vietnam business. Today's webinar will feature prepared remarks by members of Murphy's senior leadership team, followed by a live question-and-answer session. A copy of the presentation for today's webinar is posted on the investor relations section of Murphy's website. As a reminder, our webinars may contain forward-looking statements as defined under U.S. securities laws. 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, please refer to our most recent annual report filed with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements except as required by law. Throughout today's webinar, production numbers, reserves, and financial amounts are adjusted to exclude non-controlling interest in the Gulf of Mexico. Any references to the terms or modeling of production sharing contracts in today's webinar are for illustrative purposes only and do not reflect the terms of any actual contract. This information is not a forecast or indication of Murphy's strategies, business plans, or future events and should not be relied upon when making an investment decision with regard to Murphy. I will now turn the call over to Eric Hambly, our President and Chief Executive Officer. Good morning, and welcome to the third and final session of our offshore webinar series. I hope the first two webinars provided valuable insights into how we deliver differentiated value through exploration and development and clearly illustrated the importance of our growing Vietnam business. Today, we will take a closer look at the contractual framework that underpins Vietnam, the production sharing contract, also known as the PSC. Understanding the mechanics of a PSC is essential to valuing offshore projects in Vietnam and many other countries around the world. Before we dive in, here's a quick recap of where we've been in this series. In our first webinar, we discussed Murphy's unique approach to exploration and development, our strong track record in this space, and how our strategy positions us to compete and win offshore. In our second session, we highlighted Vietnam's favorable economic and political climates, strong geology in its Cuu Long Basin, and the potential for our asset base there to become Murphy's next engine of long-term shareholder value creation. In today's session, we will start with an overview of the history and fundamentals of PSCs, why they exist, how they're structured, and the key components that define the fiscal framework. We will walk through a simplified fictional PSC model and build it step-by-step using example numbers to show how cash flows and entitlement production evolve over the life of a project. The final section today will touch on important structural considerations, including multi-field development and how it can help optimize free cash flow. You will also see the effect of commodity price changes on free cash flow under both PSC and concession frameworks. By the end of today's session, our goal is for you to have a clear understanding of how PSCs work and how they fit into the broader offshore value story we've discussed throughout this webinar series. I will now turn it over to Christopher to frame the history and basic structure of PSCs. Thanks, Eric. Let's start with historical context around the origin of the production sharing contract or PSC. Before PSCs, the widely accepted model between an oil company and host government was the concession agreement, which effectively offered a tax royalty structure where the contractor realized the majority of upside benefits. PSCs were developed as an alternative to concession agreements driven by host countries wanting to attract foreign investment while also retaining more control around timing of development and capturing more of the upside from their produced hydrocarbon resources. The first modern PSC was implemented in the 1960s in Indonesia, and the model rapidly gained traction internationally. During the 1970s, the PSC had become widely adopted across emerging petroleum provinces around the world. Today, about 1/4 of the world's producing countries use PSCs as the governing contract between governments and operators. Production sharing contracts are designed to attract investment by balancing risk and reward between parties, and this balance is a defining feature of PSCs. The structure is particularly suited to capital-intensive projects as built-in mechanisms benefit the contractor during the early years of investment. Before we go further, let's take a moment to clarify how we will use the term contractor as we will refer to it throughout today's discussion. In a production sharing contract, a contractor or contractor group refers to the international oil company or the consortium of companies that hold interest in a block or permit and who are responsible for carrying out the exploration, appraisal, development, and production activities. For example, in the PSCs for our 15-1/05 and 15-2/17 blocks in Vietnam, the contractor or contractor group are comprised of Murphy, PetroVietnam or PVEP, and SK Earthon. With that, there are several key elements to the PSC. These elements serve to protect the contractor from downside risk, deliver competitive returns, and provide government profitability over the life of a project. Let's dive in a little deeper. First, once production is realized, PSCs offer cost recovery, which acts as a protection floor for the contractor. During cost recovery, the contractor receives disproportionate access to early revenue streams, allowing them to recover eligible exploration, appraisal, and development costs. For the contractor, this limits downside during the most capitally exposed phase of the project by prioritizing return on investment. Second, governments and contractors participate in profitability through profit share splits, limiting contractor upside as projects become more profitable. Most modern PSCs have a progressive sliding scale, whether price-based, volume-based, or linked to an R factor, which is a ratio of cumulative revenues to cumulative costs. These mechanisms increase government take as project profitability improves and serve to offset the disproportionate share of revenue that the contractor receives during cost recovery. On the right, we show how this compares to a generic concession agreement. Under a concession agreement, the contractor typically owns the produced hydrocarbons and bears most of the subsurface and project risk. Under a PSC, the government retains ownership of hydrocarbons, and risk and reward are more evenly shared. In summary, the PSC structure creates a stable and predictable contractual and fiscal framework that incentivizes contractor investment while simultaneously ensuring that governments receive increasing value as projects progress. Investors are often concerned about government take. A useful way to think about it is that government take is really a function of risk, reward, and negotiation dynamics. In the early stages of a basin's life, the uncertainty is high, the geology is less understood, and the investment risk is significant. Governments typically offer more competitive fiscal terms to attract capital into those more frontier investment phases. Over time, as the basin matures, when discoveries have been made, infrastructure exists, and technical risk drops, the fiscal terms naturally tighten. The graph to the right shows this through a range of modeled scenarios for different countries and illustrates why countries like Morocco and Brazil plot where they do. Morocco is high risk but offers unproven frontier upside, while Brazil's offshore basins are already proven and prolific. As mentioned during webinar two, a higher government take does not imply weak project economics. Well-structured PSCs are designed so that early returns are protected through cost recovery, and over time, profit share mechanisms scale with project profitability. This means the contractor can still generate strong returns even where government take is relatively high. This is how we approach our portfolio at Murphy. We're not optimizing for the lowest government take. We're optimizing for the strongest full-cycle returns. We target and are actively building a portfolio of projects that delivers globally competitive project economics. Fiscal terms are just one component in doing so. What truly matters is how the geology, development plan, cost profile, and contract structure work together to deliver that value. I will now hand it over to Francisco for a detailed discussion on PSC models. Thanks, Christopher. On this slide, you will see the core building blocks of a model PSC in Vietnam. Although contract confidentiality restricts us from disclosing specific terms of our contract, today we'll guide you through the key components of a typical Vietnam PSC. In Vietnam, certain components of the PSC, such as royalty and profit oil share, vary based on negotiated production tiers. Over the coming slides, our discussion will primarily focus on revenues, and then we will take this revenue back to net barrels. First key component is royalty. Royalty is levied on gross revenue, and the royalty rate is calculated based on an incremental sliding scale linked to revenue generated from daily production. In the top graph, we use a fictional sliding scale to show how the royalty rate evolves as production and associated revenue increases. The sliding scale is incremental. If the additional barrel produced falls into a higher band of the scale, the royalty rate for that barrel steps up accordingly. This is the marginal rate in the graph. The actual royalty rate across total production is generally lower than the marginal rate, as reflected by the effective rate in the graph. Second, cost recovery. All costs related to petroleum operations, including CapEx and OpEx, are fully recoverable over the life of the field. Annually, cost recovery is capped at a certain percentage of gross revenue. This cap rate is negotiable and confidential. The remaining revenue after royalty and cost recovery is considered the profit share and is divided between the contractor and the government. Finally, contractors are subject to taxes and levies as defined in the PSC. These include crude oil export tax on revenue generated from oil exported outside of Vietnam and environmental charges reflecting payments linked to environmental protection. Corporate income tax is levied on taxable income, with varying rates depending on a block's government-defined incentive status. All terms apply at a block level and are part of the agreement between the contractors and the government. In PSCs, what you sign is what you should expect all the way through the life of the contract. If the country were to introduce new laws that would impact the general fiscal terms positively, the contractors can apply for that benefit. If the host government wants to introduce new terms that have a negative economic impact, a stabilization clause is in place for the contractors to obtain relief. Let's discuss how cash flows through a production sharing contract and how project revenue ultimately translates into cash flow for both the contractors and the host government. At the project level, a full life project will incur exploration and appraisal and development CapEx upfront. Once production begins, the project starts generating gross revenue and incur operating costs. The contractor incurs all exploration and appraisal CapEx, development CapEx, as well as operating costs. These costs accumulate in a cost bank and are eligible for recovery through the PSC cost recovery mechanism. From gross revenue, the first call is royalty, which is paid to the government. Next comes cost recovery. A portion of the production referred to as cost oil or cost gas is allocated to the contractors to recover eligible capital and operating costs. While there's usually an annual max on how much production revenue can be used for cost recovery in any given year, the point is that all costs related to petroleum operations are recoverable over the life of the project. After royalty has been paid and cost recovery allocated, the remaining production is classified as profit oil or profit gas. This profit share is then split between the contractors and the government based on the agreed profit-sharing terms. From their share of profits, contractors may also be required to pay tax and other levies depending on the specific PSC structure. Stepping back from a cash flow perspective, contractor cash flow is driven by cost recovery plus profit share, net of taxes and costs. Government take consists of royalties, its share of profits, and taxes. This is the basic framework of how project cash flow is allocated between contractors and the host government. More importantly, it highlights the sequencing. Contractors recover their costs first and then share the remaining revenue with the government. As a next step, I want to walk you through the cash flow over the first 12 years of the life of a fictional project. For this fictional project, we're assuming a royalty rate of 5% and cost recovery ceiling of 50% of the annual gross revenue. As a reminder, costs will be recovered fully over the life of the project, and the ceiling applies only on the annual basis. Here, our contractor profit share and corporate tax rate are assumed to be 50%. Additionally, for the sake of simplicity, this example uses a fixed flat price of $75, OpEx of $10 per Boe, and a flat production of 15,000 barrels of oil equivalent per day. Now let's dig into the model. In the first year of the project, we incur exploration costs followed by appraisal and development costs in year two through year four. These costs accumulate in the cost bank as we have no production and negative cash flow. In year five, production starts, and we generate revenue for the first time. In this example, royalties are calculated as 5% of gross revenue. We also incur OpEx and some extra development costs which add to the cost bank. Now that we have production, we're eligible to recover costs by drawing against the cost bank, up to the ceiling of 50% of gross revenue, as previously mentioned. Unrecovered costs remain in the cost bank. After cost recovery, next step is to calculate the profit which will be shared between the contractor and the government. We subtract the cost recoveries and royalties from gross revenue. In this example, the profit is split 50/50 between the host country and the contractor. At this point, the contractor's revenue equals the contractor cost recovery plus the contractor's profit share. From this revenue, we subtract the operating costs and the corporate income tax to get to after-tax operating cash flow. Then after-tax free cash flow is calculated simply by deducting capital expenditures from the operating cash flow. Contractor's entitlement production is comprised of cost oil and profit oil, which can be calculated here by dividing the contractor revenue by the price. From years six to year nine, we continue to chip away at the cost bank, recovering our costs. Year 10 is the first year the cost recovery ceiling is higher than the remaining cost. In year 10, the project becomes cost current and has recovered all accumulated costs. Once the project is cost current, the government takes a higher share of the revenue, and the contractor's entitlement production and free cash flow decreases. The drop in entitlement production in year 10 onwards is an artifact of the mechanism of the PSC, not reservoir performance. Additionally, in this example, all prices are modeled to be flat, whereas in reality, changes in prices can introduce variations in year-to-year reported entitlement production. As we discussed on the previous slide, entitlement production is comprised of cost oil and profit oil and can be calculated by dividing contractor revenue by price. Early in the project, entitlement production is largely driven by cost recovery, as a significant share is derived from recovering the accumulated cost bank. As the project becomes cost current, the cost recovery component declines, and profit share becomes the dominant driver. The cost recovery and profit share components may vary over the life of the project, but the overall entitlement production remains more stable YoY. Starting in Q4, we will start reporting the entitlement production from our Vietnam business unit. In Vietnam, production and cost banks accumulate at a block level. This contract structure can influence how quickly incremental capital, such as tiebacks, can translate into recoverable costs and free cash flow. This is where our hub and spoke strategy, as we discussed during webinar two, will really drive value for our shareholders. Once we have our two hubs producing Golden Camel in Block 15-1/05 and Golden Sea Lion in Block 15-2/17, we will be able to recover exploration and development costs for future tiebacks against revenue from existing hubs, accelerating cash flow and adding to our net production. Let's look at an example of how our hub-and-spoke development will work and its benefits. The graph on the right represents cost recovery and profit share for a single project. Both Field A and Field B are in the same block. Sample Project A begins production in year one and becomes cost current in year four on a standalone basis. Project B, based on its standalone economics, doesn't become cost current until year seven. However, since they're both in the same block, any new exploration or development spending on Project B or any other projects in the same block can be cost recovered against Field A's production. Therefore, once we run the economics at a block level, the combined A+ B project becomes cost current also in year four. Since Vietnam's PSCs work at a block level, future development costs are recovered faster from existing revenue. This will be the case for any future activity post first oil from the Golden Camel and Golden Sea Lion hubs. This is what the Vietnam PSCs is designed to enable, to incentivize the contractor group to continue to invest and develop resources and recover these costs from prior investments. Before closing, I want to focus on how PSC mechanics translate into something equally important for investors, valuation resilience across commodity price cycles. The chart compares the net present values for two offshore fields, one under PSC structure and the other under a traditional concession regime across different oil price scenarios. The key takeaway is that PSCs dampen volatility. Since PSC prioritize cost recovery up to a revenue threshold, they allow contractors to recover capital earlier and share downside risk with the host government, resulting in more stable cash flows and lower valuation fluctuation across price scenarios. Overall, PSC provides a natural buffer in lower price environments, helping protect cash flow when prices are under pressure, while concession arrangements allow for more participation in the upside. From the government's perspective, as prices rise and profitability improves, government take increases through profit oil sharing, but the contractor still participates meaningfully in higher absolute cash flows. As we mentioned in our first webinar, our exploration portfolio is being built to perform across commodity cycles and is not just a collection of individual prospects. This portfolio balance creates durability in our ability to deliver transformational upside. Our objective is not just to maximize returns or net present value in a single price deck, but to build a portfolio that generates strong returns, supports the balance sheet, and remains attractive through commodity price cycles. A combination of PSCs and concession-based assets allow us to do exactly that. Now I will turn it over to Eric. Thank you for participating in our webinar series. We hope that our webinars helped improve your understanding of Murphy's strategy and capabilities and Vietnam's growing role within our exploration and development portfolios. The data is clear. Shale oil production will likely peak within the decade as global oil demand continues to rise, creating a supply gap which can only be filled with ongoing exploration. Today, Murphy is among a very short list of companies who have maintained the muscle to successfully explore and develop. As the industry shifted its focus to shale, Murphy continued to invest in exploration and maintained an innovative oil finder culture. Our culture and demonstrated track record allow Murphy to attract top exploration and offshore development talent and build a pipeline of opportunities with significant potential. Our recent exploration success rate of 60%, combined with our ability to develop resources 40% faster than the industry, gives us a competitive advantage that simply cannot be replicated overnight. In Vietnam, you can see Murphy's strategy in action. Our track record in Southeast Asia earned Murphy access to the country, and we now have line of sight to a material 30,000 barrel-50,000 barrel per day business there in the 2030s. We still have more exploration to do, and with our current 100% exploration success rate in the region, we're optimistic about further upside. Overall, Vietnam represents the next frontier of organic growth for Murphy, and I'm excited for our future there. As we look ahead, our entire organization remains laser-focused on our strategy to explore for untapped resources around the globe, develop them efficiently, and deliver strong execution and long-term shareholder value. Thank you for joining us throughout this series, for your engagement, your questions, and your partnership. We will now take your questions. At this time, I will open the call for the question and answer session. In order to ask a question, press star then the number one on your telephone keypad. We'll pause for just a moment to compile the Q&A roster. Your first question comes from Carlos Escalante with Wolfe Research. Your line is open. Hey, good morning, team. Thank you for having me on and thank you for walking us through the PSC mechanics as you see it. My first question is on slide five, if we can perhaps go there. You mentioned that and I think we are well aware that the basis of any conversation with the government is around risk reward and obviously fiscal terms. You've outlined multiple times throughout the past that the government take on the project is on the low 70%, so presumably between 70%-75%. My question is, if I look at that slide, and I understand that it's illustrative, you're outlining a 250 case at $75 oil, which again, I understand it's illustrative, but it sort of points to a better than what you've outlined before. The real question here is, you've said multiple times that you've been invited by the government, and so presumably you would have a fairly competitive set of terms. Just wondering if maybe you can square that away for me. Maybe it's just an illustration as a whole, but it would really help if you can provide some color there. Great question, Carlos. The terms that we've talked about, they vary somewhat significantly based on the production rate from the block. What I have said historically is 65%-75%, and if I was guessing, I'd say around 70%, which is what's really indicative on this slide. Two points to make. First, the 15-1/05 block, the PSC was signed before we entered the block. There was a supermajor operator on the block who worked on that, before we were even entered the block. We did not have an opportunity to shape those terms. They were indicative of what the terms were at the time that was created. I think that PSC was signed in 2007, so quite a long time ago. The other block we were, of course, involved in, we can't disclose the terms. What we're trying to show you here is that these are sort of if you went to look at the petroleum law in Vietnam now, you would come out with a model field that would have this type of government take. We're not intending to provide a fine-tuned number on what the government take will be from our blocks, but indicative of what you would expect for an average participant in the country now. Got it. Okay. That helps. And as my follow-up, if you guys don't mind, referencing your hub and spoke strategy, and because you are ring-fenced at the block level, what would a hypothetical successful HSV-3X exploration will mean for both your current LDV development and for a potential sanctioned HSV platform? And I'm thinking in terms of cost recovery and how you develop the field. Hey, Carlos. Francisco Garcia here. A successful HSV-3X, if you, as you know from the map, it's on the 15-1 block. What that will mean is it will put us in the realm of unitization. What will happen then is we'll create a unit for the whole development, and then each block's fiscal term will determine how the entitlement barrels will work. There could be a case if we have a successful 3X and we prove reservoir connectivity, and we're now unitizing the field, that we could be recovering HSV costs from 15-1 with the production from the Lac Da Vang. Oh, I see. All right. That's actually very helpful. Thank you. Thank you, guys. Thank you for the series. Thanks, Carlos. Your next question comes from Charles Meade with Johnson Rice. Your line is open. Yes. Good morning, Eric. I wanted to ask, I think we, I guess in the investment community, we've seen a lot of other companies publish their PSCs, you know, with escalating R factors and all those sorts of things. So I'm curious, is this driven by Vietnam that you can't disclose and, or is it instead a Murphy decision? You know, are we gonna be able to see the PSC terms for Côte d'Ivoire if something develops there? That's a great question, Charles. We are not allowed under our agreement with Vietnam to publish the terms of our PSC. If we were able to, we would publish them. As Murphy, we're not withholding information that we would like to give you. We're giving you what we can. What we're trying to do in this webinar series is give you as much information as possible that we think is helpful in order for you to create a PSC that closely resembles what we actually have without actually disclosing the terms. What I think you'll find from us over time, if we see a company like an information provider or a specific analyst that we think is particularly good at modeling our PSCs, then we may say, "Hey, why don't you have a look at so-and-so's model?" As we move forward and we think people are doing a better job or a worse job of modeling our PSCs, we'll try to help as much as we can while complying with the agreement we have with the government of Vietnam. Got it. Any implications for Côte d'Ivoire? To be honest with you, I don't know the legality of disclosing the terms in Côte d'Ivoire. I'd have to look at that. The terms in Côte d'Ivoire are very good. We showed on our webinar today sort of the risk reward, and typically PSC terms are more favorable for the contractor group when there's a less proven basin, and which I think is true of Côte d'Ivoire. The terms there are very good. In fact, they're almost as good as the United States, which is one of the best fiscal regimes in the world. They're not quite as good, but they're good. I'll have to follow up with my team later and determine what we can say about Côte d'Ivoire. I suspect we cannot reveal the actual terms because we probably would have done that already if we were able to, but I just don't have that answer. Right. If and when it becomes relevant, you'll disclose what you can, if I understand you correctly. Absolutely. We will help you as much as we can. Got it. Thanks, Eric. Thank you. Your next question comes from Betty Jiang with Barclays. Your line is open. Good morning, team. Thank you for doing this webinar series. My first question is on the production optimization and how you guys think about sizing the size of the production. Because your slide 10 shows that as your production goes up, your marginal royalty rate and the government take also goes up. But on the NPV basis, we typically think bigger boat, higher revenue, higher NPV upfront. So how do you optimize that return for the company? And could you also just clarify whether the production stacks up, like whether, say, project 1 plus tieback 1, tieback 2, does that all stack up to the total production that determines the royalty rate? Hey, Betty, Francisco here. As we mentioned in our remarks, some of the terms in the Vietnam PSC are based on production tiers. We don't really think of the tiers. We really think of value at the block level, which is what you're alluding to. What we do is we look at the combination of our hub-and-spoke strategy, and we come up with the best way to maximize block value. We run two cases usually. One is constrained facility capacity, and the other one is unconstrained. Then we figure out what does that mean in terms of CapEx investment and what does that mean in total returns. That's how we think about maximizing net present value for the block versus trying to stay within certain tiers in the production sharing contract. To add to your clarification, yes, the production stacks up, and it's all added up at the block level. Same thing with cost as well. All the costs are aggregated in one cost bank for the block level as well. That's helpful. Let me just add one comment, Betty. Yeah. When we prepare a plan of development for a field, we work it with our partners and the host government. What'll happen in the initial development is we will come up with an optimal development. Just to be clear, we don't intentionally try to stay in a certain production tier. We try to optimize total value. Yeah. We get help from that with our partners and the government. Well, we would not, nor would they allow us to have a development plan that has some kind of overly constrained production rate to try to maximize entitlement. We're really trying to create value for everybody and doing it in a very transparent, kind of open book way with the government. Got it. That's very helpful. Thank you. A follow-up on the unitization comment. If I think about HSV that straddles two blocks and the economics for HSV will be a blend of those two blocks, how does cost recovery work then? Basically, I'm trying to think, like, does HSV costs get recovered? Can LDV revenue be used for cost recovery for HSV? Yes. Cost recovery is at a block level, and the way to think about it is the costs that were incurred first are recovered first. It's sort of a first into the cost recovery pool, first to be recovered. If you go back to the very beginning, the very first exploration wells added cost for Block 15-1/05, and similarly, the first two wells we drilled on Block 15-2/17 are in the cost pool for Block 15-2/17. If we have a field that is confirmed to straddle the block boundary and we develop a unitization plan, then there would be a participation share of how much of the HSV field or Golden Sea Lion is on Block 15-1/05 and how much is on Block 15-2/17. The cost related to the part that would be on Block 15-1 would be recovered from the revenue from Lac Da Vang after the other costs on the block have already been recovered. I see. That's very helpful. Thank you. Thank you. There are no further questions at this time. This concludes today's conference call. You may now disconnect.