Murphy Oil Corporation (MUR) Q1 2021 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation First Quarter 2021 Earnings Conference Call. [Operator Instructions]. And I 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 noncontrolling interest in the Gulf of Mexico. Slide 1. 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 2. I'd like to start with why Murphy Oil that illustrates our unique assets and abilities. Murphy produces from primarily 3 sources: the 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 and successful deepwater operations in the Gulf of Mexico business, which provides a large portion of our revenue. Murphy's exhibit unique ability to execute offshore projects faster than our peers with leading drilling and completion abilities and an average 3-year project time line 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 delevering our business and returning cash to our shareholders through our long term dividend. Throughout all of this, our company has been supported by the multiple decade ownership of the founding Murphy family. Also, our Board and 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 3. Our 3 priorities this year are to delever, execute and explore. Murphy has made significant progress on delevering and derisking 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 achieved a total of $233 million of debt reduction or 8% of our total debt since year-end 2020 from these transactions. Our current strip prices are maintaining the goal of reducing debt by an additional $200 million in 2021 for a total 15% debt reduction this year. Our execution ability remains topnotch with high levels of performance as our onshore business brought wells online ahead of schedule and under budget, while our operated and nonoperated 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 2 upcoming nonoperated wells. The Silverback well was recently spud by Chevron in the Gulf of Mexico and later this year, we will turn our attention to the Cutthroat well in Brazil, Sergipe-Alagoas Basin with ExxonMobil. I'm excited to discuss these 3 simple priorities with investors and analysts today. On Slide 4, getting to the details of the quarter, Murphy produced an average of 155,000 barrels equivalent per day with approximately 63% liquids production. Significantly, our oil production was 88,000 barrels per day, which beat our guidance of 82,000 barrels per day. As shown in our 2021 quarterly well cadence, accrued CapEx with 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 nonoperated Lucius field. Overall, we spent 1/3 of our total capital plan for the year. Commodity prices rebounded significantly in the first quarter with oil realizations averaging $58 per barrel, slightly above the WTI benchmark, which we haven't seen since before the pandemic. Our natural gas realization prices averaged $2.55 per thousand cubic feet. And now I 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 5. 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 noncash impairment charge on Terra Nova and a $121 million noncash 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 off line 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 noncontrolling 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 6. 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 stair-step down for the remainder of the year. Overall, we're maintaining our CapEx plan of $675 million to $725 million for 2021. However, we are tightening our production guidance range to 157,000 to 165,000 barrels of oil equivalent per day for the full year. For the second quarter of 2021, we're forecasting a production range of 160,000 to 168,000 barrels of oil equivalent per day. Importantly, our oil production is forecast at 95,000 barrels of oil per day for the second quarter. Slide 7. As Roger mentioned, Murphy had several significant cash flow events occurring in the first -- during the first quarter. So we've tried to simplify the ins and outs on Slide 7. 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 use 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 cost 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 a 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 9, talking about our North American onshore business. Murphy continues to enhance our onshore well execution with operated wells coming on line ahead of schedule in the first quarter due to enhancements in drilling and completion efficiencies. Additionally, 16 nonoperated Eagle Ford Shale wells came online at the end of the quarter, ahead of schedule. Overall, we remain on track to bring online 3 remaining operated wells and 29 gross nonoperated wells in the Eagle Ford Shale and 10 operated Tupper Montney wells in the next 2 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 where emissions reduced, but Murphy saved $1.3 million in cost for the quarter, while bringing online 20 wells across North America onshore. We utilized approximately 800,000 barrels of recycled water across our completions programs, which Tupper Montney completions consume nearly 75% recycled water, saving $3 million in disposal costs. Further, we have reduced emissions with actions such as electrification of the third-party processing plant, which is 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 barrels equivalent per day exceeded the midpoint of our guidance for the quarter despite more than 2,000 barrel equivalent per day of impact from February winter storm. Our first quarter online wells, IP30 rate averaged 1,400 barrels of oil equivalent per day with the IP of the 2 best wells, reaching 2,000 barrels equivalents per day. Along with stronger well results, Murphy significantly reduced our costs from previous years. In 2018, our average well cost has dropped from approximately $6.3 million per well to now $4.5 million per well in first quarter of '21, with stand-alone 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 derisk 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 2 wells have outperformed our Tier 1 type curve and achieved an average IP rate of 1,400 barrels equivalent per day, and our recent Tier 1 Austin Chalk wells continue to perform in line with the type curve. Slide 11, on the Tupper Montney. Murphy produced 234 million cubic feet per day in the first quarter in Tupper and brought online 4 wells as planned. Our production was impacted in the quarter by a mechanical issue on 1 well as well as higher royalties. Drilling and completion costs continue 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 '21 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 sections have been drilled at all 3 wells as part of Khaleesi/Mormont, Samurai and the Samurai-3 well is currently drilling as the first well in the drilling campaign. The project remains on track to achieve first oil in first half of 2022. The nonoperated St. Malo waterflood project is progressing as scheduled. The first producer well is now in line, and the final well of the 4-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 is 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 advancing this arrival, and the FPS remains on track for receiving first oil from Khaleesi/Mormont, Samurai in the first half of '22. We're pleased that this construction is kept to schedule despite the global pandemic. It is an integral piece of our Gulf of Mexico projects. Murphy's industry-leading team is doing 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 '21. Our 10% nonoperated 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 nonoperated exploration position in Sergipe-Alagoas Basin in Brazil continues to progress and provides us further optionality. Today, we're highlighting our view of the resource potential at 500 million to 1 billion barrels. 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 '21, which is approximately net cost to Murphy of $15 million. Slide 19. We previously presented our long-range plan as far as 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 '24, with oil weighting averaging 50% and offshore production averaging 75,000 barrels equivalent per day. This consistency leads to significant cash flow generation. An average WTI price of $60 per barrel enables Murphy to reduce its total debt level to $1.4 billion by 2024 while maintaining a quarterly dividend to shareholders. Further, we remain focused on executing our exploration program with a portfolio of more than 1 billion barrels of oil equivalent on a net risk resource basis. After we have 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 focused priorities. As we look ahead to the remainder of the year and beyond, we remain focused on our priorities of delevering, executing and exploring. With current strip prices above $60 per barrel and strong production volumes, we're on target for an additional $200 million of debt repurchases later this year, resulting in a 15% reduction for all of '21. 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 we look forward to this year's campaign. Wrapping up, I want to thank the employees of Murphy for doing outstanding job this quarter and 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 of 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.

[Operator Instructions]. And your first question will be from Paul Cheng at Scotiabank.

I have several quick questions. First, on Austin Chalk, can you give us a rough idea that what kind of opportunity set that you may be looking at there? What is the -- if 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 Operation to 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 6 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 for Austin Chalk. So we're very excited about it. And the cash flow generation from these is really strong and it allows us to follow our focus areas of delevering, as Roger mentioned.

Eric, do you have a, say, number of prospect inventory? Any kind of, say, maybe what idea that you can share?

We have broken our Eagle Ford position out into numerous tiers of expected performance from our Austin Chalk wells. And we have likely about 100 wells that we're going to pursue over the next decade or so between our Tier 1 and Tier 2. So we're going to be reevaluating 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 1, Tier 2.

And I wondered that -- I think you're saying that current plan for the CapEx for 2021 to 2024 remain unchanged average about $600 million. Commodity price is actually quite strong and looks like that it could be stronger than everyone expected for at least the next maybe 2 or 3 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 delevering as the main focus, Paul, and feel that after that, we'll have those list of opportunities after we have our debt or further as I outlined in my call statement this morning. So no plans to change with that. And if the oil prices continue to go up, we will delever faster and be glad to do so.

And on that basis 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. When you get down to that $1.4 billion to $1 billion range, which I think is a very comfortable place to be. And at that time, having that level of debt to cash flow would be advantageous 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. And that's the way we're thinking about that. And it just so happens that the $1 billion to $1.4 billion is a good place from a debt EBIDAX multiple perspective, Paul, that would be similar to any company with an outstanding balance sheet.

Next question will be from Jordan Levy at Truist Securities.

Roger, I want to start out 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, 2 significant ones as we swap 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 those and about -- 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 delever. Our goal is to buy something if we were in that environment to be accretive to cash flow, so we could still maintain our delevering goals, which is where we are today. And 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. And then 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. And 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 delevering is our key and, of course, exploring is our key. And with exploration, we'll 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 offshore -- in our offshore business that we can fund delineation of a success in our cash flows and not hurt our delevering goals. If it gets into a major project success, more than likely, it would come along the time we are delevered 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. And 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 we feel well positioned in that going forward, which is one of our capital allocation opportunities outlined on Slide 19. So I feel very comfortable about that at this time.

Next question will be from Stephen Richardson at Evercore ISI.

I was wondering -- 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 thought -- 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 will 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. There's -- 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. And we are not today working to add in that region, but we are experiencing or have long-term knowledge about that particular situation, Steve.

Great. And 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 would review different opportunities around our role in energy transition, naturally being part of that would allow us to have more focus and information around that particular item. And I'd rather just leave it at that today, Steve, if you don't mind.

Next question will be from Gail Nicholson at Stephens.

Operating expenses were mildly elevated during the quarter. Was that all weather-related? And how should we think about LOEs for the remainder of year?

Our LOE, I'll answer the overall question and 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, it worked out very well. I would say that our total Murphy OpEx would be below where we were this quarter, which was $9.75 for total Murphy in quarter 1. I'd see us in the $8.50 range, the rest of the year as an overall company. And 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 about $5 -- just over $5 a barrel equivalent operating expenses. And then for our Eagle Ford business, it will be less than $10, probably about $9.50. So it should stabilize to kind of what you've seen from us over multiple quarters.

Great. I appreciate that color. And then turning to the Eagle Ford. The Tier 2 wells in Karnes that are outperforming that Tier 1 type curve, what's the driver that's causing that outperformance? And 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?

Yes, that's a great question. So just briefly on the Austin Chalk results. We had 6 wells in our program that we've brought online in the first quarter. 3 of them, we expected to have Tier 1 performance, and they have. 3 of them, we expected to have Tier 2 performance because of their location and their proximity to known offset historical well performance. We were very happy to see outperformance of those 3 wells that we expected to be Tier 2. They're actually significantly above our Tier 1 performance. The primary reason for the exceeding expectations was that we had less offset well control to guide a higher forecast. So it does open up a bit of a different view of how we might have tiered our future locations, but we're just evaluating that now. It's very early time data, but we are excited and encouraged by those results. In terms of our -- can you repeat the last part of your question? I'm sorry.

Of course. And 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 volumes flat now?

Yes. 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. And 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. And then can we get any update on potential on Vietnam?

Thank you, Gail, for that question about our exploration there. We're very, very excited about Vietnam. It is a place that we have not allocated capital to of late for our own reasons and our delevering focus, but it allows a very large portfolio of inexpensive lower risk opportunities that we're evaluating now. And I prefer it to be part of that post delevering process of additional capital allocated assets that I mentioned that are highlighted on Slide 19. And in closing there 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.

Next question will be from Leo Mariani at KeyBanc.

Just a 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, let's say, $60 to $65 oil versus the Tupper Montney wells with AECO prices have been kind of ranging from USD 2.25, USD 2.50 here?

Thank you for that question on our assets there, Leo. I'm going to have Eric that we have all that detail broken out by area and price. Go ahead, Eric.

Okay. Yes, that's a great question. The Eagle Ford wells that we are investing in, in our plan here this year and expectation for going forward, at sort of current oil prices, have rates of return sort of in the 35% to 100%, and our Tupper Montney wells have rates of return that are in the 60% to 90% range. So 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, but the range of the Eagle Ford returns is a little bit broader. So 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. And 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 do you think there's potential for more non-op come with higher oil prices this year?

It's been up -- thank you, Leo, for that question. I believe an emphasis for us today is to delever and keep capital expenditures in check. I think it will 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. And then we see no indication of those companies increasing CapEx nor would Murphy. So again, our goal is executing. We're executing better, executing better on our operations, which is leading to our delevering and our delevering goals, and we believe to be the case of our partners as well.

Okay. And 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 barrels a day in the first quarter. I'm not sure that was actually online for the whole quarter. So I wanted to kind of get a sense of what the total impact would be if that was just a partial quarter on the 1,100 barrels a day. And then also just on Silverback in the Gulf of Mexico, is there kind of an expectation as to when we might see a result? Is that like 1.5-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 the Silverback after that, Leo. Please, Eric.

Okay. The production from Lucius, we started recognizing beginning in February, so for the first quarter of 2021, it contributed 2 months of production. Our estimate for the year is a little over 1,300 barrels per day, net to Murphy.

On to Silverback, thank you for that question. We're really excited about that well, Leo. I'd like to emphasize again, that's a way for us for 10% working interest to derisk significant portfolio of those type of 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. And it would probably be at or past -- right past our call time, Leo, at this time. And our well cost is probably in the $10 million to $15 million range for our share of that well.

[Operator Instructions]. And your next question will be from Josh Silverstein at Wolfe Research.

Just a question on the Eagle Ford volumes. You got up to a good start this year when volumes coming in better than expected, and that's what we're rolling into 2Q. But you only have 3 operated wells coming online in the second quarter, and then you kind of mentioned the 30,000 barrel a day level, which you guys would be ahead of in the first half of this year. Can you just talk about how the volume [indiscernible]? And how the non-op volume discover activities still support that just because you guys are above that 30,000 barrel a day level in the first half.

Yes, Josh. 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 make -- to allow our onshore well -- 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. But overall, our goal and our execution there is positive toward what we want to do. And 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 nonoperated 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. So 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, very well there.

Correct. Yes. I just -- you guys certainly are -- I just wanted to understand like the expectation is that your volumes in the back half will decline though.

Yes, that's true. Josh, you're right.

Hence the goal is towards 30,000 or less based on the full year average for your...

Sure. Yes. Just wanted to clarify that. And also, our team, other kudos to our operational team on the base production has been outstanding. So several, several positives this year so far in execution, not just drilling and completion, but on production, engineering as well, Josh. Thank you for that question today.

Sure. Just one other quick volume question here and then a follow-up. So I know last year, there was a big storm here, just wanted -- in the Gulf of Mexico, just wanted to see how you guys are baking that into 2Q, 3Q guidance 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. And 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. And our production guidance now includes a downtime in the third quarter of over 5,000 barrels per day equivalent and almost 1,500 or slightly more than 1,500 barrel equivalent per day in the fourth quarter. And 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 and estimate, and we're ahead of the game now and I'm very happy where we are.

Great. And then as far as the balance sheet goes, you guys had $230 million of cash undrawn 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.

Yes, Josh, thanks for the question. As we've mentioned a couple of times here, it is clearly our plan, our intention to pay down additional debt for the remainder of the year. So to the extent that 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. And of course, any time 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. So 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.

And your next question will be from Umang Choudhary at Goldman Sachs.

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 has been a place in which we've worked for a long time as part of our overall strategy. I'd 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 and very happy to drill this well, which has outboard 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. So Brazil should get going the second half of the year. With the first opportunity there in our large acreage position, and really proud to be there on a long-term basis with our partner, ExxonMobil and participate with them going forward in a large, large prospect that we're very happy about it. We've gauged at 500 million to 1 billion barrels. So a large opportunity for us, and we're excited about it this morning.

Great. And as a follow-up, I just wanted to get your thoughts around service pricing. Are you seeing any signs of inflation, given what we're seeing in the commodity markets?

Tom Mireles has joined us today for the first time, and he heads our -- 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're committed to our Board and our shareholders when they approved our budget last year. So 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. So 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. So 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 that -- what we're seeing currently in the market.

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, and we'll be seeing you at the next call. And 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. And at this time, we do ask that you please disconnect your lines.