Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2021 Earnings Conference Call and Webcast. At this time, all lines are in a listen-only mode. Following the presentation we will conduct a question and answer session. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Thank you, operator. 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 David Looney, Executive Vice President and Chief Financial Officer; Eric Hambly, Executive Vice President, Operations; and Tom Rallis, Senior Vice President, Technical Services. Please refer to the information on slides we placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of Mexico. 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 discussions of risk factors, see Murphy's 2020 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, Kelly. Good morning, everyone, and thanks for listening in to our call today. Look at Slide 2; we'd like to briefly remind our investors of our story as each tenet of this slide remains in effect this quarter and in the future. Our ongoing execution in our three producing areas continues to support our offshore long-term projects. Our competitive advantage in executing offshore is illustrated by our outstanding progress on our Khaleesi/Mormont Samurai field and the King's Quay project. We've maintained strong cash flow due to capital discipline that covers our planned spending and debt reductions for 2021 and supports shareholders through our long-standing dividend. Lastly, our meaningful level of board and management ownership highlights our personal interest in the company's long-term success. Moving to Slide 3, closing out the quarter, we remain focused on progressing our three priorities: delever our company, execute and explore. We continued on delevering during the quarter as we redeemed $150 million of our 6.875% notes due in 2024. And earlier this week, you saw that we announced the redemption of an additional $150 million of these notes to occur in December. Therefore, we have achieved our goal of reducing long-term debt by $300 million this year. I'm even more pleased that our total debt reduction of $530 million or 17% for all of '21 has been accomplished as we progress towards our long-term debt reduction goals. We remain on schedule for our Gulf of Mexico major projects, including transporting the King's Quay floating production system to the Texas Coast, ahead of our King's Quay project with no impact, while maintaining our timing of first oil in the first half of 2022. Our strong execution and capital discipline have led us to reduce the midpoint of our capital budget by $20 million for 2021, down to $680 million. Lastly, we are pleased that the Partner Group has come to an agreement on the Terra Nova asset life extension project and work will begin in the third quarter. With regard to our exploration program, we completed drilling the non-operated Silverback exploration well during the quarter. The well has been plugged and abandoned, and Murphy has fully expensed the well. We will continue to evaluate results across our working interest blocks. Looking forward, we're excited to begin the drilling of the Cutthroat exploration well in Brazil this quarter and advance our 2022 exploration drilling plans with our partners. On Slide 4, our third quarter production of 155,000 barrels equivalent per day was comprised of 59% liquids. Hurricane Ida had a significant impact on the industry in the Gulf. We were able to safely redeploy our people offshore five days after evacuation, but we experienced minimal damage to our facilities. We could have restarted production at that time. However, the issues affecting third-party downstream assets kept our production offline longer, leading to a slow return to full activity. As a result, we had 12,800 barrel equivalents of impact due to Hurricane Ida in the quarter. Even with the storm impacts, our consistent onshore operations and capital discipline placed our net accrued CapEx at $103 million, which was below guidance. We also saw stronger realized pricing, averaging just over $68 per barrel in the quarter. Our natural gas averaged $2.77 per 1,000 cubic feet. Natural gas liquids also remained very high, averaging $33 per barrel in the quarter. On Slide 5, Hurricane Ida hit the Gulf Coast this August as a Category 4 hurricane. Its path put it directly over critical third-party offshore pipeline hubs, onshore terminals, and natural gas processing plants. This unique track, combined with the intensity and physical impacts of the storm this size, created devastation and operational loss not seen since Hurricane Katrina 15 years ago. As a result of this hurricane, Murphy's production for the year was reduced by approximately 4,400 barrel equivalents per day. Fortunately, we have long-standing agreements in place for our temporary shore bases, which enabled us to redeploy personnel quickly and safely only five days after the event, much faster than most of our peers. We were also one of the first companies able to resume our drilling following the storm at our Khaleesi/Mormont Samurai project. On the ground, we followed our disaster response plan and quickly activated our incident team, sourcing supplies and arranging transport to deploy the items to our impacted workers so they could take care of their homes and families. Overall, I believe we had an exceptional hurricane response that put us in the best position possible to resume operations as soon as third-party downstream capabilities were back online. I'll now turn the call over to our Chief Financial Officer, Mr. David Looney, to give a financial update of the company.

Thank you, Roger, and good morning, everyone. For the third quarter, we reported net income of $108 million or $0.70 net income per diluted share. Certain after-tax adjustments included a $44 million noncash mark-to-market gain on derivative instruments, a $22 million noncash mark-to-market loss on contingent consideration, and a $54 million noncash gain on asset retirement obligations due to the multiyear deferral of expected Terra Nova abandonment expenditures following the project sanctioning. As a result, we reported adjusted net income of $37 million or $0.24 per diluted share. Cash from operations for the quarter totaled $405 million, including the noncontrolling interest. After accounting for net property additions and dry hole costs of $119 million, we achieved positive adjusted cash flow of $286 million. On Slide 7, our third quarter CapEx was notably lower than original guidance for three primary reasons: Number one, we received an $18 million credit for Terra Nova from exiting owners upon close of the agreement; number two, we were able to reduce costs for various Gulf of Mexico projects by a net of $18 million; and number three, a portion of our spending was shifted from the third quarter to the fourth quarter this year due to timing differences. Overall, our capital discipline and offshore execution has enabled us to reduce our CapEx midpoint by $20 million, down to $680 million, with our range tightening to $675 million to $685 million. This is even more significant when noting that this number includes the $20 million acquisition of additional working interest in the Lucius field in the first quarter of 2021. On Slide 8, turning to the fourth quarter, we're forecasting a production range of 145,500 to 153,500 barrels of oil equivalent per day, with a midpoint of oil production at 81,000 barrels of oil per day. This range includes approximately 4,500 barrels of oil equivalent per day of Gulf of Mexico facility downtime for the quarter, which occurred in October, as well as planned non-op downtime of 2,200 barrels of oil equivalent per day later in the quarter. We are reinstating and revising our full-year 2021 production guidance with the previous low end of the range set as our new midpoint after experiencing Hurricane Ida, which averaged out to a 4,400 barrels of oil equivalent per day impact for the full year 2021. We now forecast '21 production of 156,500 to 158,500 barrels of oil equivalent per day. Our full year oil midpoint of 87,000 barrels of oil per day is up 6% from our original guide, and is forecast to comprise 55% of total production for the year. All of this reflects our priority on execution, as we have been able to lower CapEx while increasing our oil production and ultimately generate sufficient free cash flow to redeem $300 million of long-term debt, all despite experiencing production impacts from a significant hurricane. With that, I'll turn it back over to Roger.

Thank you, David. As you look at Slide 10 in our North American onshore business, our onshore drilling and completion activity is nearly complete for 2021. We plan to bring online four operated wells in the Eagle Ford Shale in the fourth quarter, and that will wrap up our program for this year. On Slide 11, in the Eagle Ford, we produced 37,000 barrels equivalent per day in the quarter, comprised of 7% oil and 86% liquids. We plan to bring online, as I just said, four wells in Catarina in the fourth quarter, two Upper Eagle Ford Shale, two Lower Eagle Ford Shale, and one in the Austin Chalk. Total CapEx for this year will remain at $170 million in this play. We are pleased that for 2021, we are now achieving approximately nine-month payout wells across our Eagle Ford Shale business. Slide 12 in Catarina. As mentioned previously, we have four Eagle Ford Shale wells coming on here this quarter. All four wells are located in our Catarina area, and we've seen incredible results this year as part of our operation, including achieving the highest oil cut in Dimmit County and producing 60% above the type curve, resulting in six-month payouts in Catarina. Other companies have also reported strong production results in this area, particularly in a new Austin Chalk zone play in this area. With our Austin Chalk test planned in the fourth quarter, we're hoping to further derisk approximately 110 Austin Chalk locations in Catarina for future development. Slide 13. In Tupper Montney, we produced 292 million cubic feet per day. Our 2021 wells have achieved record high IP 30 rates for the company and also in comparison to the industry through modifications and flowback facilities, wellhead equipment, and procedures. Overall, we're seeing IP rates more than 50% higher than the previous three years, and 19% CAGR and IP rates since 2013. As you look on to Slide 15 in our offshore business, our Gulf of Mexico projects continue to advance, and we're now drilling a final well at our Khaleesi/Mormont Samurai project before advancing to completions later in the fourth quarter. In September, we were able to quickly resume drilling following Hurricane Ida, with no impact to our schedule for first oil in the first half of next year. The non-operated St. Malo waterflood project continues to progress with the installation of a multiphase pump. We are fortunate these projects avoided the impact from the hurricane, and we're excited as we advance this moving forward. On Slide 16, the King's Quay floating production system successfully transported more than 14,000 miles from South Korea to the Texas Coast during the quarter and arrived just ahead of Hurricane Ida with no impacts. Project work continues, and the FPS will soon be moved to its final location in the Gulf, ahead of receiving first oil in the first half of next year. I'm very pleased with the incredible work that everyone has done to keep this project on schedule, especially during COVID, while remaining in a healthy and safe environment, which exemplifies our long-term offshore execution ability. Slide 17 concerns Terra Nova. During the quarter, the partner group came to an agreement on the Terra Nova asset life extension project, which is expected to extend the production life of the FPSO by 10 years. As a result of the agreement, the government of Newfoundland Labrador will be contributing up to USD 164 million in royalty and financial support, with the three partners contributing in aggregate on a matching basis. Murphy's total future net investment in the project will only be $60 million. Work has begun on the FPSO, which was sent to Spain for dry dock through most of next year before an anticipated online date in the fourth quarter of 2022. On Slide 19, regarding exploration in the Gulf, we continue to hold a sizable exploration position in the Gulf and we're excited that we will have a lease sale on November 18 that is moving forward with no changes in royalty rates or other matters. Last quarter, our operating partner, along with other major energy peers, completed drilling the Silverback exploration well. The well has been plugged and abandoned, and Murphy expensed the well. We continue to evaluate results across our working interest swaths. Slide 20 concerning Brazil. We're excited to work with our operating partner this quarter to spud the Cutthroat exploration well in the Sergipe-Alagoas Basin in Brazil, with an approximate net cost to Murphy of only $15 million. We hope this well is the first of many in the basin and look forward to the optionality and resource potential the well provides. As you look at our long-term strategy on Slide 22, our disciplined long-term plans remain intact as we continue on our path of delevering, executing, and exploring. As previously disclosed, we're targeting an average CapEx of $600 million from '21 through '24, with production CAGR of only 6% during that period. Our long-term oil weighting remains at approximately 50% through 2024, and this combined with our average 75,000 barrels of equivalent per day produced offshore, will support significant free cash flow generation. We plan to maintain a low production CAGR and capital discipline, even in a period of these higher prices we're seeing. This will allow Murphy to pay down debt faster and advance returns to shareholders, and we have no plans to change the strategy at this time. Our debt will be reduced by half, down to $1.4 billion by the end of 2024, averaging only WTI $55 per barrel pricing. Further, our strong cash flow will continue to support our cash returns to shareholders. Our exploration program and portfolio of more than 1 billion barrels equivalent net risk potential continue to be another focal point for our company. Longer term, we appreciate the optionality afforded us with significant free cash flow generation as well as our ability to allocate capital more broadly between funding asset development, exploration success, additional debt repurchases, and returning more cash to shareholders. On our focused priorities on Slide 23, our team has done a tremendous job this year remaining focused on our priorities that we have achieved; I'm sorry, a lot as a result of this discipline. As announced earlier this year, we'll be redeeming another $150 million of senior notes, thereby achieving our delevering goal of $300 million in long-term debt this year. This is a great first step in our plan of reducing total debt in half by the end of '24. Assuming long-term oil prices of $55 per barrel, at current share prices, we're able to achieve this one year earlier. We continue to execute well on our major Gulf projects as well as reducing onshore drilling and completion costs through ongoing efficiencies. Most importantly, we maintain a safe work environment for our employees, contractors, and surrounding communities. Lastly, our priority of exploring supports Murphy's longevity so that we may continue to produce oil and natural gas to achieve our mission of providing energy that empowers people for the next 100 years. We achieved this by participating in the drilling discovery in Brunei earlier this year. We're excited about the prospect in Brazil that will spud later this quarter with our operating partners. Further, we're advancing and finalizing our 2022 exploration plans and partnerships as everyone completes their budgeting process, and we're looking forward to next year's opportunities. In closing, I'd like to congratulate all our employees for another quarter of strong execution and capital discipline. I'm thankful that everyone remained safe during Hurricane Ida, and I'm incredibly appreciative to those who displayed Murphy's values and helped our colleagues' families clean up and begin repairs to their homes following the storm. With that, I'll turn the call back to the operator for your questions at this time. Thank you.

Your first question comes from Neal Dingmann with Truist. Please go ahead.

Rod, obviously been pretty excited about the upcoming Cutthroat and I'm just wondering, besides that, could you maybe talk about your thoughts on, I know it can vary, but potential timing around that well? And then any other sort of notable exploration wells you'd consider around the quarter?

Thank you, Neal, for that question about our program. That's one of our key tenets and a differentiator for us. We see that well here pretty soon, Neal. I'd really like to leave the comment at that. But we're hopeful to spud the well this month. As far as next year's program, we're looking at finalizing our budget. It's typical for us to be drilling a nice well in Mexico and another well in the Gulf of Mexico, which we would both operate. Those will be nice wells, especially the Gulf well, with Mexico being a larger well in terms of resources, and we are happy about those and have a lot of opportunities in both places to drill; that is in our plans at this time, Neal.

And then just one follow-up, I'd really like to see that near-term upside at Same Mile on the waterfloods. I'm just wondering, would you consider or is there potential for bringing some other waterfloods on in the coming quarters? I don't know what the plans for that is.

No, today, thank you, Neal, for that. Historically, waterflood projects have really been international. You may not know this, but we are one of the leaders in water injection and deepwater in the world because Malaysia was developed totally in that way. It's very uncommon in the Gulf. There are some of these big Wilcox projects that will have this. It's a different cost structure here and a different reservoir type development in the Gulf. It's not that common. We are evaluating Dalmatian, which has been tied to more of a reservoir energy perspective to St. Malo and we're looking at that in our long-term plans.

Your next question comes from Paul Cheng with Scotiabank. Please go ahead.

A number of questions. You talked about the balance sheet starting to quickly get back to shape and you're going to accelerate the cash return. Can you talk about between, say, a fixed dividend, variable dividend, and buyback, how should we look at when you reach the point you will be able to accelerate the return, and what are the conditions for that to happen?

Thank you, Paul. That's a good question for us and a company that does have a long policy. Like many others in 2020, we reduced our long-standing dividend by a significant portion of 50%. We still feel that we're a very good dividend-paying company. We combine that with our capital discipline that we've been exhibiting here to allow us to allocate our free cash flow to really reduce our debt, Paul. We want to get our debt in half, as we've said, and as I mentioned earlier this morning, we plan to reduce our debt in half by the end of '23 with the current pricing. So we know that we're an established company, and we want to achieve lower debt while returning cash to our shareholders. That's been our practice and is no surprise. At current prices, as I just said, we'll be able to accomplish those objectives at a faster pace. And if this were to occur, we do have one big advantage in our company: with only 154 million shares outstanding, the increase discussed by our peers really isn't a substantial amount for us. So that would be under evaluation in the near term along with our budgeting and pricing. We'd like to lower the debt first, and we're hopeful to get the debt done. But a simple increase in the dividend is not a costly venture for more fuel.

And Roger, can you clarify where both dividend and buyback fit in? Are you going to have excess cash in addition, because as you say, you only have 154 million shares? We think the fixed dividend should not necessarily tie up a significant amount that you really want to raise it higher, as is the case with excess cash flow. So between the variable dividend and buyback, does the Board have a preference one way or the other?

We have been so focused on our deleveraging, which is the left-hand pillar of our three focus areas, Paul, quite honestly. That's our first step. Naturally, as you approach budgeting season with oil, around 80 different views can take place. I don't want to get ahead of my board on that, but I would say at Murphy, we're more inclined towards dividends and getting our dividend back. We've been a dividend payer for 60 years. That would be our preference. Of course, a variable dividend can come into that mix. Given our current share count, that would be the basis today, Paul.

And the second question is on hedging. With the balance sheet getting in better shape, should we be looking at hedging? Are you going to significantly reduce your hedging position going forward, or will you continue aggressive hedging? Strategically, why do a lot of hedging if you have a strong balance sheet and your reinvestment rate is relatively low?

Yes, Paul, I'm going to provide just a high level and let David provide more of that detail. We are not going to be a company that hedges more than about 45,000 a day or more for oil. We have some mixtures, some protections to ensure that we do not ever have to go to the bond market for the '24 notes that we've greatly reduced, and that's our overriding concern at this time. I'll let David provide you with more specifics on that, Paul.

Yes, Paul, great question. By the way, thank you for that. The way we think about hedging at this point, as you suggested, is really in the context of our continued debt reduction plan, which is, of course, 50% by 2024. Roger mentioned we don't ever hedge more than about 50% of our anticipated oil production. Recently, as you've seen, we chose to utilize collars for the remainder of our '22 program. We've been able to achieve a floor price of about $62, a little bit more than that at an average ceiling of almost $75. We like this structure because it provides us with some downside protection, so that if certain events were to occur in the oil market, we still generate significant cash flow from those hedges, which would allow us to continue our debt reduction plan. Of course, if prices stay where they are today, we will reap the benefits of those higher prices, which, as Roger mentioned earlier, would also enable us to pay down our debt faster. Thus, we consider it in that context, and we have never really been a company that hedged beyond 12 to 18 months, aside from our gas position in Canada and the Montney. That's our consistent approach historically, and I believe we're sticking with that now.

Final question, Roger. There's a lot of assets up for sale, including, I think, Conoco, after they closed the Shell deal, which likely will do quite a lot of term asset sales. Petrobras, with your product in the Gulf of Mexico, is also putting its asset up for sale. Can you talk about the company's stance on M&A? Are you looking at it as a buying market or a selling market from your perspective?

Well, Paul, thank you for that question. We have been very active in M&A, both selling and buying over the last eight years for sure. I think we've executed $8 billion of deals in the company to reposition ourselves and it's helping us pay down debt, providing us with a lot of EBITDA per barrel. We look at a lot of M&A opportunities. I would say we focus our M&A efforts in offshore. We have ample locations in onshore and we'd like to see our onshore business running extremely well right now at consistent production, ensuring it remains a long-term free cash flow provider like our shale peers today. Offshore, we see a competitive advantage in certain assets and specific challenges. Instead of saying buying or selling market, it has to meet a certain rate of return based on our analysis of PDP and 2P type reserves in a price deck with the information that we have as long-term offshore players. That type of return will supply the free cash flow necessary to be accretive to all of our debt reduction metrics. We are a known operator and can review lots of offshore properties, adding value through cost structure improvements to most things. So that's how we view it today, Paul. Thank you for that question.

Your next question comes from Charles Meade of Johnson Rice. Please go ahead.

Roger and David, I had a little difficulty getting back on the line, but I'm glad I did. Good morning to the rest of your team there. Roger, I'm wondering if you can share with us, I imagine you have something like a Gantt chart or some kind of schedule that you're keeping an eye on for tracking the progress of King's Quay and your start-up. Can you share with us what the key milestones and heavy lifts are that you are really focused on?

Thanks, Charles, for that question about King's Quay. There is indeed a Gantt chart. It has 723 lines on it, and they usually condense it down for me, Charles, so we can understand it. There is a lot going on there. We're doing very well, very, very well. We visited the facility recently, and it's the most advanced facility at this stage of the game I've seen in my career. It's in great shape, ready for the tow out in about a week or so. To me, the main tasks are towing it out, which should not be a problem, and securing the mooring or prelay. We have a lot of pipelines to lay in the field for each well and manifolds; there are two vessels currently in the field laying pipe. We will be towing the vessel out very soon and establishing the mooring. Then we are out in the field drilling. We have interface management to manage that. This is common to our business, and we feel well positioned at King's Quay today. However, there are always many items to execute, but I feel really good about King's Quay and the associated infrastructure that's on the mud line to facilitate production from these three fields—Khaleesi, Mormont, and Samurai—and we feel really pleased with the execution of the facility and the pipelines, etc.

So if I understood you, Roger, the focus is really on getting the facility out there, securing the mooring line, and completing the ongoing infield flow line laying. Is that right?

Yes, if I wasn't clear enough, Charles, I apologize. That is the key part. Additionally, the rig has to complete the wells on time, and we want to maximize the flow of how many wells we can have before first oil. So it's a matter of organizing that. We may flow earlier with fewer wells or later with more wells. The rig must complete the wells across these projects, which have already been pre-drilled with pay at Khaleesi and Mormont. We are still drilling at Samurai, but we are progressing daily and have been quite fortunate and very pleased with our progress.

And then if I could ask a question regarding the Petrobras sale of their remaining 20% interest in your JV. Can you offer any comments on that process? And do you have anything like a preferential right for that 20%?

Thank you, Charles, for that question. Yes, the Petrobras deal has been a very, very beneficial agreement for our company, assisting them as well. They wanted to exit while still retaining partial ownership. I believe they would be very pleased with our execution and progress thus far. They have decided to sell their interest, and we do have a preferential right. We'll be analyzing that, but I want to emphasize that we would like to focus on the risk factors, but we truly understand all the underlying assets since a lot of them are ours, and we've been running them for a long time. We feel advantaged in that respect. However, they will have a process; we are likely going to participate in it and see how that unfolds.

Next question comes from Leo Mariani with KeyBanc. Please go ahead.

I wanted to just touch base on the Silverback well here. Did you find any hydrocarbons in that well? What type of information do you think you may have garnered, since I believe you have a bunch of other acreage in the area?

Thanks, Leo, for that question on exploration today. What I can say about it is, yes, we did find some hydrocarbons in that well. The well is being evaluated, and we are tying that into our blocks and to the blocks that we farmed into. However, we expensed the well, and it has been plugged and abandoned, and we have limiting disclosure among our partner group on it, Leo, quite frankly. That's all I can share at this moment.

Just touching base, Roger, in your prepared comments, you mentioned your longer-term plan from '21 to '24 targeting around $600 million of CapEx with a 6% CAGR in production. I wanted to confirm if that's still the thinking from you folks? Also, I recall the plan anticipated '22 being the high point for capital due to much of the King's Quay CapEx rolling through. Could you also comment on inflation and any impact that might have on CapEx over that plan?

Thanks for that question, Leo. Before I respond, I want to emphasize that approximately two years ago, we developed this plan to ensure our onshore businesses could sustain operations, supporting our Montney long-term projects, offshore projects, debt reduction, and all that—we've performed admirably in that direction. I am proud that after another year of adjustments, we can maintain all the components of our long-term strategy. Regarding as to CapEx for next year, yes, it will be higher. As I've indicated previously, it will be the higher year for the reasons you've mentioned. I'm very pleased with our plan, and high oil prices are assisting us in faster deleveraging while maintaining the long-term strategy slide numbers that I mentioned in my comments; I'm genuinely satisfied with that. As for inflation, I'd like Tom Mireles to discuss our perspectives on that matter, as he handles technical services at the company, which also includes supply chain. Here's Tom.

All right. Thanks, Leo. Yes, this is definitely something we keep a close watch on, and our supply chain group coordinates with our operations group to make adjustments that enable us to deliver on our plan, as Roger described. This year, we saw some tightening in the market following the global economy's recovery, but fortunately, it didn't impact us significantly. Most of what we planned for '21 was already under contract, particularly with respect to Gulf of Mexico projects involving long lead items. Regarding next year, we are indeed observing some categories experiencing rising costs; however, others, such as OCTG, have decreased. Earlier this year, we discussed our ability to drill our onshore wells for about $5.5 million each, and we anticipate delivering the same next year. This is achievable due to adjustments in our design and operations for the wells. Additionally, in the longer-term view Roger mentioned, we've factored in some modest inflation around 3%. So a lot of what he's referring to has that consideration embedded in the longer-term outlook.

As a final question, I wanted to address exploration. It appears you have a well planned in Mexico for next year. I wanted to get your thoughts on how you rank Mexico from an exploration perspective, given the recent changes in the political and regulatory environment there. Do you view Mexico as being less prolific than a couple of years ago due to those shifts?

Thanks, Leo, for that inquiry. No, I don't see that changing in any way regarding the production potential in Mexico. We have been able to permit and gain approvals for everything we've ever needed. While there are some issues related to other matters like unitization and corresponding regulations, which we're not part of, several European majors have reported success in the trend we're drilling. We are the operator there, and that also constitutes an advantage. It is well offshore, and we feel comfortable with that segment of the business, treating it like another promising exploration well in progress, similar to a project seismically in our historical work in the Gulf of Mexico. I don't perceive that as an issue impacting us significantly.

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.

I appreciate everyone calling in today, and we'll be talking to you at the end of our next quarter with our budget and related matters. Thanks for joining; see you next time. Thank you.

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