Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2021 Earnings Conference Call. If at any time during this call you need assistance, please press star zero for the operator. I would like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead. Good morning, operator, and thank you everyone for joining us on our First 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 Mireles, Senior Vice President, Technical Services. Please refer to the informational slides we've 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 interests in the Gulf of Mexico. Slide one. Please keep in mind that some of our 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 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. Turning to slide two, I'd like to start with why Murphy Oil? That illustrates our unique assets and abilities. Murphy produces from primarily three sources, Eagle Ford Shale, Gulf of Mexico, and onshore Canada. Unconventional Eagle Ford Shale and onshore Canada assets have complementary characteristics, which enables our onshore team to leverage shared capabilities and expertise. Further, we have deep roots in successful deepwater operations in the Gulf of Mexico business, which provides a large portion of our revenue. Murphy's exhibited unique ability to execute offshore projects faster than our peers with leading drilling and completion abilities and an average three-year project timeline from sanction to first oil. Our leading offshore execution capability augments our high-potential exploration portfolio. Our assets achieve low carbon emissions intensity, which we believe will be in the top quartile as compared to our oil-weighted peers at the end of 2021. They continue to generate high levels of cash flow, which are directed toward de-levering our business and returning cash to our shareholders through our long-term dividend. Throughout all of this, our company's been supported by the multiple decade ownership of the founding Murphy family. Also, our Board of Directors and Management Team maintain one of the industry's highest levels of ownership compared to our peers, and we all have personal interest in our company's long-term success. On slide three. Our three priorities this year are to de-lever, execute, and explore. Murphy's made significant progress on de-levering and de-risking our company in the first quarter with the monetization of our share of King's Quay floating production system and issuing new senior notes, utilizing proceeds to fully repay our revolver and take out senior notes that were due in 2022. Overall, we'll achieve the total of $233 million of debt reduction or 8% of our total debt since year-end 2020 from these transactions. At current strip prices, we maintain the goal of reducing debt by an additional $200 million in 2021 for a total 15% debt reduction this year. Our execution ability remains top-notch with high levels of performance as our onshore business brought wells online ahead of schedule and under budget, while our operated and non-operated offshore projects remained on schedule. Our oil production beat guidance by 7% this quarter, while our Eagle Ford Shale assets in particular were 4% above guidance despite experiencing impacts from the winter storm in Texas. Lastly, as we continue advancing our unique high-potential exploration program, we're excited for drilling the two upcoming non-operated wells. The Silverback well was recently spudded by Chevron in the Gulf of Mexico, and later this year, we will turn our attention to the Cutthroat well in Brazil's Sergipe-Alagoas Basin with ExxonMobil. I'm excited to discuss these three simple priorities with investors and analysts today. On slide four, getting to the details of the quarter. Murphy produced an average of 155,000 bbl equivalents per day with approximately 63% liquids production. Significantly, our oil production was 88,000 bbl per day, which beat our guidance of 82,000 bbl per day. As shown in our 2021 quarterly well cadence, accrued CapEx was first quarter weighted and totaled $230 million net to Murphy. This amount excludes King's Quay spending but includes our $20 million acquisition of an additional 3.5 working interest in the non-operated Lucius field. Overall, we spent a third of our total capital planned for the year. Commodity prices rebounded significantly in the first quarter, with oil realizations averaging $58 per bbl, slightly above the WTI benchmark, which we haven't seen since before the pandemic. Our natural gas realization prices averaged $2.55 per 1,000 cu ft. I now will turn the call over to our Chief Financial Officer, Mr. David Looney, to give a financial update. Thank you, Roger, and good morning, everyone. On slide five. For the quarter, we recorded a net loss of $287 million, or $1.87 net loss per diluted share. After adjusting for several one-off after-tax items, such as a $128 million non-cash impairment charge on Terra Nova and a $121 million non-cash mark-to-market loss on crude oil derivatives We reported adjusted net income of $10 million, or $0.06 adjusted net income per diluted share. Regarding Terra Nova, operations there have been offline since December of 2019. We recorded the impairment charge during this quarter due to the current status of operating plans. However, Murphy, other partners, and stakeholders continue to evaluate options that could support a long-term production plan. Cash from operations for the quarter totaled $238 million, including the non-controlling interest. After accounting for property additions of $258 million and proceeds from asset sales of $268 million, we achieved a positive adjusted cash flow of $248 million for the quarter. On the hedging front, Murphy continues to protect its future cash flow in the Tupper Montney with additional fixed price forward sales contracts for a portion of production all the way through 2024. Slide six. As Roger mentioned, our 2021 CapEx plan is heavily weighted towards the first quarter, with $230 million in total accrued CapEx, or 33% of the annual total. Approximately 44% of total Eagle Ford Shale CapEx for the year was spent in the first quarter, while nearly 40% and 35% of the annual planned CapEx were spent in the Gulf of Mexico and offshore Canada, respectively. Onshore Canada, I'm sorry, respectively. This cadence will continue to stairstep down for the remainder of the year. Overall, we're maintaining our CapEx plan of $675 million-$725 million for 2021. However, we are tightening our production guidance range to 157,000 bbl-165,000 bbl of oil equivalent per day for the full- year. For the second quarter of 2021, we're forecasting a production range of 160,000 bbl-168,000 bbl of oil equivalent per day. Importantly, our oil production is forecast at 95,000 bbl of oil per day for the second quarter. Slide seven. As Roger mentioned, Murphy had several significant cash flow events occurring during the first quarter, so we've tried to simplify the ins and outs on slide seven. In addition to cash from operations nearly covering our regular CapEx, we received funds of $268 million from monetizing the King's Quay floating production system. We used these funds to pay off the $200 million outstanding on our revolving credit facility, as well as $18 million in King's Quay CapEx that was incurred during the quarter. We also issued $550 million of new senior notes, raising proceeds of $542 million. This was used to pay off $576 million of 2022 notes. Once you take into account the $34 million of early redemption costs related to the payoff of those notes and account for dividends and other amounts, we ended up with an $80 million cash deficit, which was covered from cash on hand. At the end of the first quarter, we had $231 million of cash and equivalents available and had repaid a net $233 million, or 8% of total debt, as Roger mentioned. At current commodity prices, we have a goal to repurchase an additional $200 million of senior notes later this year for total debt reduction of approximately 15% for the full- year 2021. With that, I'll turn it back over to Roger. Thank you, David. I'll be moving now to slide nine, talking about our North American onshore business. Murphy continues to enhance our onshore well execution, with operated wells coming online ahead of schedule in the first quarter due to enhancements in drilling and completion efficiencies. Additionally, 16 non-operated Eagle Ford Shale wells came online at the end of the quarter ahead of schedule. Overall, we remain on track to bring online three remaining operated wells and 29 gross non-operated wells in the Eagle Ford Shale and 10 operated Tupper Montney wells in the next two quarters. Our drilling and completion teams have worked hard to reduce the company's environmental impact by using clean-burning natural gas instead of diesel in drilling and completion activities. Not only were emissions reduced, but Murphy saved $1.3 million in costs for the quarter by bringing online 20 wells across North America onshore. We utilized approximately 800,000 bbl of recycled water across our completions programs, which Tupper Montney completions consumed nearly 75% recycled water, saving $3 million in disposal costs. We have reduced emissions with actions such as electrification of the third-party processing plant, which has secured power primarily from hydro in our Tupper Montney gas plant from the previous natural gas power supply. On slide 10, our Eagle Ford Shale production of 30,000 bbl equivalent per day exceeded the midpoint of our guidance for the quarter, despite more than 2,000 bbl equivalent per day of impact from February winter storm. Our first quarter online wells IP 30 rate averaged 1,400 bbl oil equivalent per day, with the IP of the two best wells reaching 2,000 bbl equivalent per day. Along with stronger well results Murphy Oil has significantly reduced our costs from previous years. In 2018, our average well cost has dropped from approximately $6.3 million a well to now $4.5 million per well in first quarter 2021, with standalone completion costs down 40% during that period. I'm proud of the work our team has done and the meaningful impact it is having on our company's bottom- line. As we work to de-risk our Austin Chalk acreage in Karnes County, we're pleased to see the strong well results achieved in the first quarter and the potential they create for our Austin Chalk location count in the future. Our Tier two wells have outperformed our Tier one type curve and achieved an average IP rate of 1,400 bbl equivalent per day. Our recent Tier one Austin Chalk wells continue to perform in line with the type curve. Slide 11. On the Tupper Montney. Murphy produced 234 million cu ft per day in the first quarter in Tupper and brought online four wells as planned. Our production was impacted in the quarter by a mechanical issue on one well, as well as higher royalties. During drilling and completion costs continued to improve for this asset as well, with an approximate 28% reduction since 2017. Average total well costs are now approximately $4.1 million in the first quarter of 2021 as compared to $5.5 million in 2019. Looking at our Gulf of Mexico projects on slide 13. Murphy's major projects in the Gulf continue to advance as planned. The top hole section has been drilled at all three wells as part of Khaleesi/Mormont and Samurai, and the Samurai three well is currently drilling as the first well in the drilling campaign. The project remains on track to achieve first oil in the first half of 2022. The non-operated St. Malo water flood project is progressing as scheduled. The first producer well is now online, and the final well of the four-well total campaign is currently being drilled by the operator. On King's Quay, on slide 14, as previously announced, we closed the monetization of King's Quay Floating Production System in the first quarter. Construction's now complete with the sail away to the Gulf of Mexico planned for the third quarter of 2021. Moorings are currently being installed in the field in advance of its arrival, and the FPS remains on track for receiving first oil from Khaleesi/Mormont and Samurai in the first half of 2022. We're pleased that this construction has kept to schedule despite the global pandemic. It is an integral piece of our Gulf of Mexico projects. Murphy's industry-leading team has done an exceptional job in executing this significant project. Exploration, slide 16. We're excited to be partnered with Chevron as the operator for the Silverback prospect in the Gulf of Mexico, which commenced drilling in the second quarter of 2021. Our 10% non-operated working interest provides access to 12 blocks with potential for an attractive play opening trend and is adjacent to a large position currently held by Murphy and our partners. On slide 17, our non-operated exploration position in Sergipe-Alagoas Basin, Brazil, continues to progress and provides us further optionality. Today, we're highlighting our view of the resource potential at 500 million - 1 billion bbl, again, illustrating what a significant opportunity Brazil is for our company. Murphy, along with the operator ExxonMobil and partners, plan to spud the Cutthroat well in the second half of 2021, which is approximately net cost to Murphy of $15 million. Slide 19. We previously presented our long-range plan as part of our fourth quarter earnings and highlight that the plan remains unchanged. By maintaining average CapEx spend of $600 million annually, we forecast a production CAGR of approximately 6% through 2024, with oil weighting averaging 50% and offshore production averaging 75,000 bbl equivalent per day. This consistency leads to significant cash flow generation. An average WTI price of $60 per bbl enables Murphy to reduce its total debt level to $1.4 billion by 2024 while maintaining a quarterly dividend to shareholders. We remain focused on executing our exploration program with a portfolio of more than 1 billion bbl of oil equivalent on a net risk resource basis. After we halve our debt levels, we have the option to reduce debt further towards $1 billion. When debt reduction is behind us, we will do what is best for the company and shareholders based on market conditions while balancing increased asset development, funding exploration success, potential A&D opportunities, and of course, returning cash to shareholders. On to slide 20 on our focus priorities. As we look ahead to the remainder of the year and beyond, we remain focused on our priorities of de-levering, executing, and exploring. With current strip prices above $60 per bbl and strong production volumes, we are on target for an additional $200 million of debt repurchases later this year, resulting in a 15% reduction for all of 2021. By maintaining conservative capital spending, we project the total debt to be $1.4 billion by 2024, with potential for further reductions beyond that level. Murphy is committed to operating safely, in particular as we continue moving forward on our major offshore projects ahead of first oil in the first half of 2022. Our onshore drilling and completions team have done a tremendous job improving our cost efficiencies and bringing wells online ahead of schedule, all while finding ways to cut emissions intensity and operate with minimal environmental impacts. Lastly, looking forward with our partners to drill exploration wells in the Gulf and Brazil this year, and look forward to this year's campaign. Wrapping- up, I want to thank the employees of Murphy for doing an outstanding job this quarter in executing the business safely and according to plan, within budget, and in some cases, ahead of schedule. We've set a strong foundation for the remainder of the year and for our future drilling campaigns with the work done to reduce costs and environmental impacts. I'm pleased with all the hard work and your accomplishments. That's all I have this morning, and I'll turn it over to the operator for our questions. Thank you. Thank you, sir. Ladies and gentlemen, if you do have any questions, please press star followed by one on your touchtone phone. You will then hear a three-tone prompt acknowledging your request. If you would like to withdraw your question, simply press star followed by two. If you're using a speakerphone, we do ask that you please lift the handset before pressing any keys. Please go ahead and press star one now if you have questions. Your first question will be from Paul Cheng at Scotiabank. Please go ahead. Thank you. Hey, good morning, guys. Good morning, Paul. Roger, several quick questions. In Austin Chalk, can you give us a rough idea about what kind of opportunity set that you may be looking at there? Successful as you hope, how big is the inventory that we may be talking about? Okay, Paul, I think it's best to have Eric Hambly, our Head of Operations, provide that color for you this morning. Thanks, Paul. It's a great question. We are really excited about the potential of our Austin Chalk program. We saw very solid results from the six Austin Chalk wells we brought online this year. With the performance of those wells, we'll be reassessing our tiering and expectations from future wells over the next few quarters, and we'll determine a plan forward for our Austin Chalk. We're very excited about it. The cash flow generation from these is really strong and allows us to follow our focus areas of de-levering, as Roger mentioned. Eric, do you have a number of [prospect] inventory? Any kind of maybe rough idea that you can share? We have broken our Eagle Ford position out into numerous tiers of expected performance from our Austin Chalk wells. We have likely about 100 wells that we're going to pursue over the next decade or so between our tier one and tier two. We're going to be re-evaluating that tiering and incorporating future Austin Chalk locations into our co-development strategy for our Eagle Ford position. It's a bit premature to right now update our overall assessment of Austin Chalk in terms of the distribution of those wells between tier one, tier two. Roger, I think you're saying the current plan for the CapEx for 2021 - 2024 will remain unchanged average about $600. Commodity price is actually quite strong and look like that it could be stronger than everyone expected for at least the next maybe two or three years. Is that in any shape or form that change your program or that you're just going to stick to it and any excess cash is just going to pay down debt? Thank you, Paul, for that question on our long-range plans and higher oil prices. Actually, Paul, we're sticking with this plan. We have a very nice program. We're very well-positioned where we are on our oil production levels, happy with our outstanding execution, and just going to stay with our de-levering as the main focus, Paul, and feel that after that, we'll have those lists of opportunities after we halve our debt or further, as I outlined in my call statement this morning. No plans to change with that. If the oil price continue to go up, we will de-lever faster and be glad to do so. On that interest that you mentioned, the long-term debt target of $1 billion, is that the target you need to reach before you will consider the alternative use of cash or that before you get there, you may start looking at? That's a good question, Paul. Thanks for that call or question on our debt targets. Just so happens that in a $55 world, you do get toward that magical 1.5 kind of level of debt EBITDAX. You get down to that $1.4 billion-$1 billion range, which I think is a very comfortable place to be. At that time, having that level of debt to cash flow would be advantageous to us to start our other alternatives. From an A&D perspective, though, Paul, we've been very active in that space through the years. There are opportunities that are accretive to cash flow that we could execute on and review that would still allow us to make that debt level in that time frame. That is something we continually review with our team. That's the way we're thinking about that. It just so happens that the $1 billion-$1.4 billion is a good place from a debt EBITDAX multiple perspective, Paul. That would be similar to any company with an outstanding balance sheet. Thank you. Thank you, Paul. Thank you. Next question will be from Jordan Levy at Truist Securities. Please go ahead. Morning, Roger, David, Kelly. Roger, I want to start off by getting your thoughts as it kind of relates to the competitive environment, mainly in the Gulf of Mexico, but in all your offshore assets. Specifically, I wanted to get your thoughts on if you've seen that change at all with either new entrants or some old names getting more interested given the rise in prices and what opportunities you see that possibly creating if you have seen a change there? Thank you so much for that question on our Gulf of Mexico business. We are uniquely positioned there. I'd like to point out that we have done deals in the Gulf, two significant ones as we swapped from international to Gulf a few years ago. That's paid off very nicely for us. We see more deal flow, more deal rumor, more deal discussion here in town than we've seen of late with people changing or wanting to change. We're of course, aware of all of those and happy to hear about other opportunities. The uniqueness I just went through with Paul a few minutes ago, we have to keep in mind that our goal is to de-lever. Our goal is to buy something if we were in that environment to be accretive to cash flow, so we could still maintain our de-levering goals, which is where we are today. We believe those opportunities exist. We like the rumors on the street. We like to talk. We're enthused by that and happy about that, and happy to be the fourth largest operator in the Gulf of Mexico. That's really helpful. Thank you. No, thank you. Just quickly, my second question is just in regards to the $600 million CapEx level, specifically how you're thinking about that in the context of an exploration success, whether it be in Brazil or in another region, how you think about flexing around that capital allocation if the exploration plays out, and it ends up being something that's accelerated. Thank you for that question on our exploration business. I appreciate that. We'll have to keep in mind and emphasize here today that, again, the de-levering is our key, and of course, exploring is our key. With exploration will hopefully come success, and we're part of some significant wells this year. We believe in our capital forecasting and flexibility, especially on the tails of this outstanding execution that we're seeing in our onshore business and in our offshore business, that we can find delineation of a success in our cash flows and not hurt our de-levering goals. If it gets into a major project success, more than likely it would come along the time we are de-levered quite a good bit and allow us then to have the cash flow as our CapEx greatly drops off post the execution of our offshore assets that we have today. When we have that drop off, we feel that we could fund our share of a major discovery based on what we see from the other successes in this hemisphere that are widely known, and that we feel well-positioned in that going forward, which is one of our capital allocation opportunities outlined on slide 19. I feel very comfortable about that at this time. Great. Thank you so much. Thank you. Thank you. Next question will be from Stephen Richardson at Evercore ISI. Please go ahead. Good morning. Good morning. Hi. Good to hear from you, Roger. One of the things, Roger, we've been wondering about is tracking a number of companies that are looking at exploiting brine resources for lithium in Arkansas. Considering the corporation's legacy in Arkansas, I was wondering if you could talk a little bit about if indeed the corporation still has land or mineral rights in those areas, and if you've contemplated any role for Murphy in that emerging business, which looks like it'll have pretty significant growth over the next couple of years. Thank you, Steve, for that question about our uniqueness. That would be something would place us in a unique position. What I'd like to point out to you today is, yes, we do have about 10,000 acres of royalty lands in Union County, Arkansas, the home of the founding Murphy family in our corporation. We do have royalty income from brine. We are closely monitoring the extraction of the brine for lithium. As you know by covering that company, I believe, that there's a project, a big, large-scale extraction project that we're monitoring that. We are not today working to add in that region, but we are experienced and have long-term knowledge about that particular situation, Steve. Great. Do you think, Roger, not to put the cart before the horse, but do you think that there is a role for Murphy in this business potentially longer- term beyond, obviously minerals and participating from a royalty perspective is really attractive, but taking a more direct participation? We, as usual, like most companies, will review different opportunities around our role in energy transition. Naturally, being a part of that would allow us to have more focus and information around that particular item. I'd rather just leave it at that today, Steve, if you don't mind. Great. Thanks very much, Roger. Oh, thank you. Thank you for asking. Thank you. Next question will be from Gail Nicholson at Stephens. Please go ahead. Good morning, Gail. Good morning, Roger. Operating expenses were mildly elevated during the quarter. Was that all weather related, and how should we think about LOE for the remainder of the year? Our LOE, I'll answer the overall question, turn the Montney particular question over to Eric. Thank you for asking that today. What I'd like to emphasize today is our LOE is going to be pretty standard throughout the year. We do have occasional workover in the offshore Gulf, which of course are very economic, work out very well. I would say that our total Murphy OpEx would be below where we were this quarter, which is $9.75 for total Murphy in quarter one. I'd see us in the $850 range the rest of the year as an overall company. I'll have Eric Hambly here, Head of our Operations, discuss the Tupper operating expenses for you, Gail. Thanks, Roger. The first quarter results were influenced by a workover at the St. Malo field, which slightly elevated our offshore operating expenses. If you look at the full- year, as Roger mentioned, our OpEx will be a bit lower on a full- year basis. If we look at some assets specifically, the Tupper Montney, for example, we expect just over $5 a bbl equivalent operating expenses. For our Eagle Ford business, it'll be less than $10, probably about $9.50. It should stabilize to what you've seen from us over multiple quarters. Great. I appreciate that color. Turning to the Eagle Ford, the Tier two wells in Karnes that are outperforming that Tier one type curve, do you know what's the driver that's causing that outperformance? When you look at the strength of the Eagle Ford results and the efficiency gains that you continue to see in the region, can you talk about how you're thinking about current CapEx to keep Eagle Ford volumes flat now? Yeah, that's a great question. Just briefly on the Austin Chalk results. We had six wells in our program that we've brought online in the first quarter. Three of them we expected to have Tier one performance, and they have. Three of them we expected to have Tier two performance because of their location, and their proximity to known offset historical well performance. We were very happy to see outperformance of those three wells that we expected to be Tier two. They're actually significantly above our Tier one performance. The primary reason for the exceeding expectations was that we had less offset well control to guide a higher forecast. It does open up a bit of a different view of how we might have tiered our future locations. We're just evaluating that now. It's very early time data, but we are excited and encouraged by those results. Can you repeat the last part of your question? I'm sorry. Sure, of course. In just looking at the strength of the Eagle Ford results and the efficiency gains that you've continued to achieve, can you just talk about how you're thinking about what CapEx is needed to keep Eagle Ford volume flat now? Yeah. We've talked about this question before, and we will, of course, every year update our forecast. We are targeting to maintain Eagle Ford production flat over many years at about 30,000 net BOE per day. The way I would frame that is we expect somewhere around $200 million of total CapEx per year in the Eagle Ford to accomplish that. Great. Thank you. Can we get any update on potential on Vietnam? Thank you, Gail, for that question about our exploration there. We are very excited about Vietnam. It is a place that we have not allocated capital to of late, for our own reasons, in our de-levering focus. It allows a very large portfolio of inexpensive, lower risk opportunities that we're evaluating now. I prefer it to be part of that post de-levering process of additional capital allocated assets that I mentioned that are highlighted on slide 19. In closing there, it just represents the unique nature of our exploration assets and the way we have to create value in places and with optionality on capital spending and timing, and very pleased to have our Vietnam acreage. Great, guys. Great quarter. Thank you. Thank you, Gail. Thank you. Next question will be from Leo Mariani at KeyBanc. Please go ahead. Good morning, Leo. Hey, morning here. Just question on kind of the return profile of the onshore drilling program. Just wanted to get a sense. I mean, it certainly looks like your Eagle Ford wells are performing nicely, and so are some of the Chalk wells to start the year. When you look at the returns on those wells, on an IRR basis or however you guys want to look at it, how do those compare at, say, $60-$65 oil, versus the Tupper-Montney wells, with AECO prices have been kind of ranging from two and a quarter to $2.50 U.S. here. Thank you for that question on our assets there, Leo. We'll have Eric, that we have all that detail broken out by area and price. Go ahead, Eric. Okay. Yeah, that's a great question. The Eagle Ford wells that we are investing in our plan here this year and the expectation for going forward, at sort of current oil prices, have rates of return sort of in the 35%-100%, and our Tupper-Montney wells have rates of return that are in the 60%-90% range. We see a tighter range of expected rates of return within Tupper. The very best of our Eagle Ford locations are a bit better than our Tupper investments. The range of the Eagle Ford returns is a little bit broader. That's kind of how I would frame that. We're really excited about both of them and think we have a great position to invest in with tons of optionality going forward, and we're excited to keep executing our plan. Okay. Just on the Eagle Ford, you obviously saw some higher non-op activity, I think, than expected here, in the first quarter. Do you think that's an acceleration from later in the year, or you think there's potential for more non-op to come with higher oil prices here? Thank you, Leo, for that question. I believe an emphasis for us today is to de-lever and keep capital expenditures in check. I think it would be quite common to our peers, quite common to the folks that we're working with, which are very known successful Eagle Ford Shale and North American onshore players. All the big names are our partners there. We see no indication of those companies increasing CapEx, nor would Murphy. Again, our goal is executing. We're executing better on our operations and which is leading to our de-levering and our de-levering goals. We believe to be the case of our partners as well. Okay. Just looking at the Gulf of Mexico here. Obviously, you guys made this working interest acquisition in Lucius. I think you guys said it was about 1,100 incremental bbl a day in the first quarter. I'm not sure that was actually online for the whole quarter. I wanted to get a sense of what the total impact would be, if that was just a partial quarter on the 1,100 bbl a day. Then also just on Silverback in the Gulf of Mexico. Is there an expectation as to when we might see a result? Is that like a one and a half month type of well, and any estimate of the potential dry hole cost there if it's unsuccessful? I'm going to have Eric handle the question you have in onshore, and I'll take Silverback after that, Leo. Please, Eric. Okay. The production from Lucius, we started recognizing beginning in February. For the first quarter of 2021, it contributed two months of production. Our estimate for the year is a little over 1,300 bbl per day net to Murphy. On to Silverback. Thank you for that question. We're real excited about that well, Leo. I'd like to emphasize again, it's a way for us for 10% working interest to de-risk a significant portfolio of those type opportunities we have in our acreage that we purchased from LLOG. The well is ongoing now by Chevron, and the well probably will be near or slightly post our call in August result, if the well is able to be executed on time. It would probably be at or right past our call time, Leo, at this time. Our well cost is probably in the $10 million-$15 million range for our share of that well. Okay. Thanks, guys. Thank you, Leo. Thank you. As a reminder, ladies and gentlemen, if you do have any questions, please press star followed by one on your touch-tone phone. Your next question will be from Josh Silverstein at Wolfe Research. Please go ahead. Morning, Josh. Hey, good morning, guys. A question on the Eagle Ford volumes. You got off to a good start this year with volumes coming in better than expected, that's something rolling into 2Q. You only have three operated wells coming online in the second quarter, you kind of mentioned the 30,000 bbl a day level, which you guys would be ahead of in the first half of this year. Can you talk about how the volumes [audio distortion] and how the non-operated volumes and other activities support that, because you guys are above that 30,000 bbl a day level in the first half? Yes. Leo, I'll frame this and have Eric get into the details. Thank you for that question. Our emphasis again is to, as an overall perspective of our company, to allow our onshore oil fields to be flatter production profile to achieve maximum free cash flow with oil price increase. That is the overall goal of how we're working there. We have been very excited about our trajectory and our execution, but you're right, we have less wells going forward in the future. Overall, our goal and our execution there is positive toward what we want to do. I'll have Eric here frame for you the rest of the year. Okay. Thanks, Roger. We are forecasting second quarter production from Eagle Ford nearly 38,000 BOE per day, and a full year of 32,000 BOE per day. The non-operated wells that are in our program that have not already come online in the first quarter, we expect to come online in the second and third quarters. Our operated program, as you highlighted, will end in the second quarter. We will have decline due to new well performance, of course, and we're happy to see that our base decline from our wells brought online prior to this year continues to be in line with our forecasted 24%. That's significantly supporting our Eagle Ford program this year and our strong cash flow generation. I would further add color on that, Josh, to say that the 32,000 is above our original plans and ahead of our 30,000 goal, and we're doing very well there. Correct. Yeah. You get some of there. I just wanted to understand, the expectation is that your volumes in the back half will decline, though. Yes, that's true, Josh. You're right. Go towards 30,000 or above based on the full- year average for your. Oh, sure. Yes. Just wanted to clarify that. Also our team, other kudos to our operational team on the base production has been outstanding. Several positives this year so far on execution, not just drilling and completion, but on production engineering as well, Josh. Thank you for that question today. Sure. Thanks. Just one other quick volume question here, and then I'll follow- up. I know last year it was a big storm year in the Gulf of Mexico. Just wanted to see how you guys are baking that into 2Q for you guys this year. Yes. Let me turn to that part here. As you know, hurricanes are part of our business, and we have a process for dealing with that. The way I like to think about this is like this. We estimate storm downtime from decades of storm data here, and we assume an average storm year based on a lot of detail, Josh, on that matter. Our production guidance now includes the downtime in the third quarter of over 5,000 bbl per day equivalent and almost 1,500 or slightly more than 1,500 bbl equivalent per day in the fourth quarter. That's the way we estimate our storm downtime and feel good about that situation, Josh. Again, it's part of our execution and something we're working on in estimate, and we're ahead of the game now, and I'm very happy where we are. Great. As far as the balance sheet goes, you guys had $230 million of cash under a revolver at the end of the first quarter. Do you guys see yourself just building cash throughout the course of the year? Are you building cash to take out the 2024 maturity early, or just waiting to see what happens with the exploration program later on this year to make some decisions? I'll let David go ahead with that question for you, Josh. Yeah, Josh, thanks for the question. As we've mentioned a couple of times here, it is clearly our plan and our intention to pay down additional debt for the remainder of the year. To the extent that the cash does build up over the next several quarters, I think, in all likelihood, you would see us do something probably towards the end of the year in terms of taking out additional debt. We're very fortunate to have several issuances on our books, bonds on our books that have attractive call features that we could take advantage of towards the end of the year. Of course, anytime we do that, we're trying to look at maximizing the amount of debt we can repay in conjunction with where the bonds are priced, et cetera. A lot of different things go into that discussion and analysis, but that's probably what we're looking at towards the end of the year. Great. Thanks, David. Thank you, Josh. Thank you. Your next question will be from Umang Choudhary at Goldman Sachs. Please go ahead. Morning, Umang. Good to hear from you. Question. Exploration is a key differentiator for Murphy. Any update you can provide on Brazil, which looks like could be a significant opportunity for the company? Yes. Thank you for that question on our exploration business. We're very excited about Brazil. Brazil's been a place in which we've worked for a long time as part of our overall strategy. I like to point out that we have this key well this year, and for the first time today, as I mentioned in my script, we have outlined our view of the size of that. Very happy to drill this well, which is outboard of a lot of success in that area. We also have the Potiguar Basin, which is moving along nicely as well, in the same type of exploration overall strategy. Brazil should get going the second half of the year, with the first opportunity there in our large acreage position. Real proud to be there on a long-term basis with our partner, ExxonMobil, and participate with them going forward in a large prospect that we're very happy about it. We've gauged it 500 million bbl-1 billion bbl. Large opportunity for us, and we're excited about it this morning. Great. Thank you. As a follow-up, I just wanted to get your thoughts around service pricing. Are you seeing any signs of inflation given what you are seeing on the commodity markets? Tom Mireles is joining us today for the first time, and he heads all of our procurement and other services in the company. I'm going to let him close you out with that this morning. Thanks, Umang, for the question. We certainly do try to stay on top of any potential cost pressure impacts on our program. Our priority right now is delivering the volumes of value that we committed to our Board and our shareholders when they approved our budget last year. Fortunately, we're in a good position through our strategic sourcing. Our 2021 program is not really exposed to the current increases that we're seeing in some costs. When we look ahead at 2022, we feel we'll be able to continue to deliver attractive returns to our program. While we see some potential cost increase coming in key services, we also continue to improve, as Eric highlighted earlier, just through cost efficiency, through efficiency gains in our execution. We also like to work with our providers that we can be able to deliver mutual benefit. It's something that we stay on top of, but currently our 2021 activity is well-positioned so that we're kind of shielded from what we're seeing currently in the market. Thank you. Thank you. Appreciate it. Thank you. There are no further questions from our phone lines, and I would like to turn the call back over to Roger Jenkins for any closing remarks. Thanks everyone for dialing in today. We had a good quarter and proud of all our work that we've done here. We'll be seeing you at the next call. Thank you so much. Appreciate it. Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. At this time, we do ask that you please disconnect your lines.