Good morning, everyone, and welcome to the Murphy Oil Corporation Third Quarter 2020 Earnings Conference Call. I will now hand the call over to Kelly Whitley, Vice President of Investor Relations and Communications. Please proceed.

Thank you. 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; and Eric Hambly, Executive Vice President, Operations. Please refer to the information on slides we placed on the Investor Relations section of our website as you follow along our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude non-controlling interest in the Gulf of Mexico. 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 2019 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.

Thank you, Kelly. Good morning everyone and thanks for listening to our call today. We continue to successfully execute our focus strategy, with Murphy steadfast in the goal of keeping a strong balance sheet through commodity price cycles and planning to allocate free cash flow to reduce overall debt levels and support an oil price recovery. Despite the record-breaking hurricane season this quarter, we still achieved free cash flow above our dividend. Our third quarter results were helped by the flexibility and strength of our multi-basin portfolio, as production from our oil-weighted offshore and onshore plays continues to see higher margins, driven by a lower cost structure. We know that to remain in business over the long-term, we must operate in a conscientious manner, protecting and supporting not only our employees but also the areas in which we work. As disclosed in our recent 2020 Sustainability Report, I'm proud to say we have proactively established a greenhouse gas emission intensity reduction target of 15% to 20% by 2030. We are further advancing our diversity and inclusion programs and practices. A multi-basin portfolio provides additional risk reduction and flexibility. We remain committed to our focused exploration portfolio, and our partners as we see it has the ability to deliver company-making resource upside to our shareholders. Looking back on the quarter, Murphy produced 153,000 barrel equivalents per day, with 86,000 barrels of oil per day. Production was significantly impacted by the historical Gulf of Mexico storm season, bringing down the expected output of 12,000 barrel equivalents per day, compared to our guidance of just under 5,000 barrel equivalents per day. This impact was partially offset by stronger performance in our onshore business. We spent approximately $120 million of accrued CapEx in the quarter, including $19 million for the construction of the King’s Quay Floating facility. Our various oil pricing points traded closer to WTI in the quarter than usual due again to the unique storm season. This led to a realized oil price of nearly $40 per barrel, which is on par with WTI. Our realized natural gas price continues to improve at $1.78 per 1000 cubic feet in the U.S. Further in the Tupper Montney, the AECO/Henry Hub basis differentials are producing and tightening due to improving market access from infrastructure build-outs and less capital spent in the region by our peers. I will now turn over to discuss the financials with our CFO, David Looney.

Thank you, Roger and good morning. Like our peers, ongoing low oil prices continued to affect our business, resulting in a net loss of $244 million, or negative $1.59 per diluted share for the third quarter. Several non-cash charges impacted earnings for the quarter, including after-tax impairments of $146 million, primarily related to the Cascade and Chinook fields in the Gulf of Mexico. There were also non-cash mark-to-market losses on crude oil derivatives and contingent considerations of $66 million, and restructuring expenses and unutilized rig charges of $8 million. After backing out these items, Murphy had an adjusted net loss of $24 million, or negative $0.15 per diluted share. With oil prices off their record lows, our net cash provided by continuing operations improved to $209 million in the third quarter, including a cash outflow of $28 million due to a working capital increase. When combined with property additions and dry hole costs of $134 million, including $23 million for King’s Quay, we had positive free cash flow of $74 million in the quarter. Excluding the working capital change, we would have achieved free cash flow of $102 million. Following our budget changes and cost-cutting measures taken earlier this year, we have maintained strong liquidity of $1.6 billion, including $220 million of cash as of September 30. Our G&A expenses continue to trend in the right direction, and we remain on track for achieving approximately $100 million in total G&A reductions between 2019 and 2020. Lastly, Murphy has taken additional action to protect its future cash flow with additional 2021 crude oil hedges, as well as fixed price forward sales contracts for a portion of our Tupper Montney production through 2024.

Thank you, David. On Slide 8, Murphy's long history of protecting our environment, employees, and all of our stakeholders has been achieved in part through our strong corporate governance processes. We continue to achieve low spill and recordable incident metrics, also reducing environmental impact with flaring reductions and increased water recycling. We've also expanded our internal diversity inclusion practices and programs and maintain a program to aid impacted employees in towns in need through our Disaster Relief Foundation, which is taking place now, as we're impacted by hurricanes on the Gulf Coast. Our operations team has made ongoing efforts to reduce our environmental impact while lowering costs due to changes such as electrification of our practice and opening a remote operating center for managing all onshore Canadian operations. Overall, these small changes add up to a larger, longer impact by reducing downtime and costs while improving the efficiency of our field employees. Additionally, we utilized bi-fuel hydraulic frac spreads for all well completions in Canada this year, which resulted in considerable CO2 emissions reductions. On Slide 9, we recently released our 2020 Sustainability Report, which features expanded disclosures and metrics and more closely aligns to various reporting frameworks, including TCFD and SASB. A key highlight of our goal is reducing greenhouse gas emissions intensity by about 15% to 20% by 2030 from 2019 levels. This report also outlines diversity disclosures, workforce development, and employee engagement programs. Murphy has also expanded our HSE Board Committee to include oversight of corporate responsibility. We formed an ESG Executive Management Committee and created a new director of sustainability role. We will continue to evolve and advance our sustainability efforts. On slide 11, like most peers, Murphy is taking deliberate actions to ensure a sustainable business in the New Energy landscape. Prior to COVID, we streamlined our portfolio to high margin oil-weighted assets to accretive deals. We refinanced certain bonds last year and are maintaining our liquidity with a manageable debt structure. Post-COVID, we continue streamlining and reducing costs, with adjustments in capital and dividends. We maintain operations in multiple basins with focused exploration opportunities in certain countries outside the United States, providing us with portfolio diversification for long-term resilience. Looking at our Eagle Ford Shale business, the asset produced nearly 35,000 barrels equivalent per day in the quarter, which is ahead of our guidance. We continue to see improvements in our base oil performance and have established low decline rates, reutilizing our remote operation center and operating model to lower downtime and optimize artificial lift performance. Production from the wells brought online prior to 2019 delivered over 20,000 barrels equivalent per day this quarter, demonstrating a decline of less than 14% over the prior 12 month period. We anticipate a 2021 base decline of just 22% for our Eagle Ford asset, which is a significant improvement in base decline. On Slide 14, Murphy produced 13,000 barrels equivalents per day in the Kaybob in the quarter with 4 wells online. This asset continues to show strong well performance with tightening differentials and is achieving higher cash flow metrics. Our team has done a tremendous job improving the efficiencies across their onshore business. Our new remote operating center in Fox Creek, Canada, manages all onshore Canada production activity and well performance, which will enable us to reduce downtime and costs through more expedient repairs. On Slide 15, our Tupper Montney wells produced 235 million per day in the quarter and continue to generate positive free cash flow for the year. Since our last earnings call, Murphy has added fixed price forward sale contracts in AECO and at the Malin Hub through 2024, locking in further price protection. As stated earlier, we've seen improving basis differentials and higher prices coupled with higher EURs and strong execution ability. In the Gulf, Murphy produced 59,000 barrels equivalent per day in the Gulf of Mexico this quarter, which was negatively impacted by record-breaking storm downtime of 12,000 barrel equivalents per day. This situation has also caused a delay in achieving first oil at Calliope, which is now scheduled to produce in the second quarter of '21. The non-operating Kodiak and Lucius wells remain on schedule, with Kodiak executing later this year. Lucius drilling is ongoing with strong results in the first well of the program. On Slide 18, regarding our long-term projects, our Khaleesi, Mormont, and Samurai projects, as well as the non-operated St. Malo Waterflood development, remain on schedule. Construction on King’s Quay Floating Production system has advanced and is approximately 77% complete, with mid-22 remaining as a target for first oil. At this time, we've submitted all permits for the Khaleesi, Mormont, and Samurai projects. We're excited to launch the drilling campaign in the second quarter of '21 and take the next step toward first oil. Two rigs are presently drilling at the St. Malo Waterflood project, and the first producer well has shown results as planned. We continue to progress our various exploration projects as we maintain optionality across our diversified portfolio. This quarter, our operating partners encountered delays in drilling due to the significant storm season. Our plans in Vietnam are moving forward with partners signing the joint operating agreement on Block 15-2. We remain excited about the opportunities here with over 900 million barrels of oil equivalent of net risk resources across our exploration portfolio. For the fourth quarter, we anticipate production in the range of 146,000 to 154,000 equivalents per day. Guidance has been impacted by two factors: actual storm downtime earlier this quarter of 8,000 barrel equivalents per day and planned downtime of around 6,000 equivalents per day as well. We maintain our full year 2020 capital expenditure guidance of $680 million to $720 million and note that $649 million has been spent through the third quarter. Additionally, we're on track to reduce full year G&A expenses by $100 million in 2020 and improve our liquidity position by paying down our revolving balance. We maintain a deep-rooted safety culture at Murphy, leading to strong HSE performance throughout 2020, including safety protocols established early in the year to protect our employees and contractors from COVID-19. Murphy has made significant progress on our long-term Gulf of Mexico projects this year. At this time, all permits submitted for approval are in advance of our campaign launching next year. Meanwhile, our onshore team is preparing to launch our 2021 Eagle Ford drilling program. Going forward, as previously stated, we plan to maintain a flatter production profile in the range of 150,000 to 160,000 barrel equivalents, with CapEx in line with 2020 spending for 2021. Our focus remains on cash flow CapEx parity after dividends, with debt reduction in a price recovery. As noted in our 2020 Sustainability Report, we have been more focused on having sustainable and transparent operations, including our proactive goal of reducing greenhouse gas emissions intensity. We will continue to allocate capital to our unique exploration program. In closing, I'd like to thank our talented group of employees for their innovations and dedication this year, in light of all the challenges we've faced. I'd like to turn the call over back to the operator for our question period. I appreciate you this morning. Thank you.

Thank you. Your first question comes from Duncan McIntosh from Johnson Rice. Duncan, please go ahead.

Thanks. My first question would be on ’21 and kind of nothing has changed versus what you messaged on the second quarter. But what are some of the things that you could do that might put you more towards the higher or the lower end of that 150 to 160?

Well, really, we feel real good about that, we are working toward that. I think our main focus is to stay with that range and get our CapEx in a way where we can have recovery prices and generate more free cash flow and reduce debt. So really, we're not that interested in moving it up and down based on the assets we have today, clearly for this quarter. With the guidance that we have, you could also account for the production we've already lost due to this significant hurricane season, but we have a pretty robust set of production going into the year. We are really looking at executing this and not wanting to make any levers to move it up or down. I feel good about hitting that target, and keep in mind too that we have almost $300 million set aside for capital for Khaleesi, Mormont, and Samurai, as well as St. Malo. So, the production that we have and the CapEx we have for cash flow CapEx parity to pay our dividend and stay within our liquidity is our main focus rather than production increases at this time, Duncan.

Okay, thank you very much. And then, since I know it’ll get asked anyway, on King’s Quay and the sell-down processes, any update there, are things still progressing or have any of those slots been taken out? So, just kind of how you're thinking about that now?

Yeah, I'm going to talk about that, and thanks for asking that. On King’s Quay, really I made a mistake that I rarely make in business development. We've done a lot of business development here at this company. And that’s commenting on a closing timing of a business, and making this way that’s negotiated, I'm not going to be doing that further. But I will say that it is progressing. King’s Quay continues to progress. There was an email on my phone before walking in here. But naturally, I’m focusing on this meeting at this time. King's Quay is a very valuable midstream asset for our company. It's an asset that is almost completely de-risked. It's been built through COVID, which is no easy task for our team, so we built through the significant typhoon season that hit that project as well twice, and it is now 80% complete. King's Quay is set on top of a very valuable field and Khaleesi, Mormont that’s been previously drilled that we purchased. So, its value has not diminished at all with this closing delay. Currently, there are two groups involved with this closing: an owners group and a producing group. With our owners group, we've made a clear directional path forward, and we are now working with our producing group toward closing. So, I am pleased with the work in progress. It's a good de-risked asset, and we are progressing with settlement. I'm just not getting involved with the date of all that here, Duncan, to be honest with you.

Yes, sir. I appreciate it. Thank you.

Your next question comes from Neal Dingmann from Truist Securities. Neal, please go ahead.

Morning Roger, could you please correct me if I say too much regarding the Green Canyon?

I'm having a little trouble understanding, could you please speak a little slower for me here?

Sure. I just was wondering about Green Canyon 895. I know there are storms this time, anything you could talk on timing, etcetera around it?

No, this is a rig operated by another partner. It's an experienced partner that we know well. They've had downtime with the rig pulling the rods and various things that happen in typical offshore exploration in the Gulf this time of year. We are in the middle of recovering from the last storm and getting set up back on the rig to kind of know where we're going forward. We progressed the oil, drilled through salt, and made a lot of significant progress. But it's really held up due to hurricane reasons, primarily right now, which would be the case with almost any rig operation conducted this quarter in the Gulf.

And then just for a follow-up, I was wondering about Canadian production, nice increase in the third quarter, I think by 6% Canadian, I should say, onshore production. Could you give comments on there? Do you think that could continue in that regard or anything you could talk about the onshore Canada?

Our Canadian operations are performing exceptionally well, and it's important to acknowledge the significant events that have occurred. We are closing our office there and focusing our efforts in Houston. As noted earlier, we have established a remote operating center that has contributed to our impressive results, especially given our efforts on the G&A side and the office relocation. The Duvernay shale is currently yielding strong performance, offering us considerable flexibility for the future. This year's well performance has exceeded our expectations, surpassing guidance for the asset. Although pricing has fluctuated below that of the Eagle Ford due to various differentials in the Gulf Coast and reduced capital spending in Canada, we are still seeing success. The Montney area is also showing excellent results in terms of decline rates, and our dedicated focus on minimizing downtime through these operating centers has significantly improved our operations in the Eagle Ford. Eric and his team are concentrating on base production with limited capital, and the Eagle Ford is currently experiencing a remarkably low base decline, the lowest we've ever recorded. Tupper is similarly performing well, with the Duvernay asset producing 13,000 barrels per day at prices slightly below those of the Eagle Ford. Many unique developments are occurring in Canada that are often overlooked. The AECO market is positive, and we've made progress on initiatives discussed a few years back. By 2022, we expect an additional 1.5 BCF of new gas supply in pipelines, despite a decrease of 2 BCF a day in overall supply due to COVID. Gas demand in Canada is improving, with plans to switch some volumes to 5 BCF a day and another LNG project anticipated in 2025. The hub performance has significantly recovered from its lows between 2016 and 2019, presenting a favorable outlook due to these pipeline developments. Canada is on a promising trajectory, improving our flexibility within our diverse portfolio. If we engage in various activities, opportunities will arise over time, and that's the situation we're currently facing with this asset.

Great details. Thanks, Roger.

Thank you.

Your next question comes from Gail Nicholson from Stephens. Gail, please go ahead.

Good morning, Roger. You guys have done a really nice job of LOE both in the Karnes as well as the Eagle Ford. Looking at the Eagle Ford, with the artificial lift optimization and facility optimization that you guys are doing that lowers the baseline, does that also have a positive development potentially on LOE going forward?

Yeah, I'm going to let Eric take all that glory and let him answer that question for you.

It's a great question. Obviously, the more we can get production from our base, and continue to lower operating costs, the stronger performance we have on free cash flow. We're pretty happy with Eagle Ford having just over $8 of BOE OpEx in the third quarter. Our per BOE OpEx in Eagle Ford is, of course, dependent to a fair bit on capital allocation going forward. So, we are giving a lot of focus on what 2021 looks like. But we are working very hard as an operations team to continue to maximize production and minimize spending, and I'm really happy with how my team has done on that.

But overall OpEx levels for us this quarter are good, with a bunch of the Gulf shut down. That's also hard to do on a per BOE basis, very hard to accomplish.

Yeah, I think I was going to mention. I was wondering if $10 unchanged number per BOE is a good run-rate to use in the Gulf going forward, or when we return to kind of a normalized rate ex-downtime, that will likely be better given the workovers?

It's going to be in that range. But ex-workovers, I think we're really in good shape on OpEx in the Gulf; we're doing really well there and working on a bunch of plans to improve it.

Great. And then, Roger, you guys have submitted all the permits for Khaleesi and Mormont and Samurai. Can you just talk about what's the next piece of the puzzle? Is it approval or just the standpoint of any clarity on timing of that?

Well, there's a lot of complexity around that with this, a lot of discussions regarding the administration change that affects the relevant departments and the continuation of operations across all administrations. We hope to gain our approvals and would like to have those approvals in January, as you would anticipate, before January of ’21. We're working toward that while keeping in mind that the documentation process is quite extensive. We feel really good about our position. We've gone through a lot of presidents in seven years and a lot of different things. This incoming administration was also part of a prior attempt to stop drilling in Macondo. We're very much aware of those historical actions, but to keep them focused on these fields, which have already been drilled, is an advantage since the requirement for completion is different from drilling permits. Keep in mind that what drilling entails is unknown pressure regimes, which alleviates some of these issues imposed on us post-Macondo by the prior administration. All of these things are clear to us, as we are knowledgeable about navigating these processes. Murphy always has alternative options with our outstanding Canadian assets, and thousands of locations in the Eagle Ford exploration, outside of the United States. It is rare to find all of these in one single endeavor. So that’s the current state of affairs, Gail.

Wonderful. And then just from the standpoint of the 2022 notes. You guys have an undrawn credit facility, cash on hand. You have the flexibility to adjust budgets to ensure you generate free cash in '21. Just wanted your updated thoughts on how you guys are thinking about those upcoming maturities?

Yeah, Gail. This is David Looney talking. I mean, obviously, we have a total of $578 million coming due in '22, not quite evenly split between June and December. We obviously keep an eye on the bond markets, and candidly where the bond markets are today and where our paper is currently trading is certainly not attractive to us at this time. But as we've seen over the last several years, there's a high correlation between where bonds trade and what oil prices look like. So, we don't have to do anything immediately, obviously. We still have over a year and a half before that first maturity. We consider all options carefully as we watch the market continuously. We remain prepared to act if and when necessary, assuming the market moves in our favor.

Great, thank you so much.

Thanks, Gail. I appreciate it.

Your next question comes from Roger Read from Wells Fargo. Roger, please go ahead.

Good morning, Roger. How are you doing?

Doing great, Roger.

I guess a couple things I'd like to make sure I understand a little better. You mentioned a couple of different times that Eagle Ford Shale well, the base decline is really, I don't know if we call it shallow at 22%, but certainly better than what we typically see. I just wondered what all is factored in there? Is that a larger base of truly mature wells that are declining slower or something you've done differently, such as choking back production early on or a combination of factors?

What we've done is right-size this asset around 30,000 a day going forward, a really low maintenance charge to accomplish that CapEx. That’s really what we're doing. I'll let Eric expand further on that for you, Roger.

Sure. I mean, we have a natural phenomenon with the shale oil wells that have a shallowing decline through time. If you look at our Eagle Ford this year and what our thoughts are in terms of the base performance next year with fairly limited capital allocation to Eagle Ford in 2020, we have less production from high decline rate wells. We have established, as we comment on our slide deck, a 20,000 barrel-a-day piece of our business from wells brought online prior to 2019, which has demonstrated very shallow declines, which of course, we expect to continue to shallow going forward. So, our focus on managing our base on limiting downtime, maximizing production, and increasing well performance through artificial lift optimization allows us to shallow out our decline even more than the natural phenomenon. We’ve been happy to observe this performance over the last 12 months and expect it to continue going forward as the wells naturally shallow out and decline as well.

Okay. So just kind of isn't all of the above processes really the right way to think about it?

That's correct. Everything you said.

All right. Then, I don't know which one of you all wants to take this, but on the CFO parity for dividend and CapEx, and also the desire to pay down the debt that's out on the revolver. I'm just curious, where does the extra cash come from to pay down the revolver? Is it just based on oil, like $44 for parity, $45 you're going to move it around as oil prices move around? Just a little more help on that?

Well, as I said, I'm not really getting into it today, Roger, I'm sure you can understand why. But when we sell down this asset to take our revolver to zero this midstream asset that we have, King's Quay, if not, that would stay on there in a low-40 world, because cash flow CapEx parity with dividend otherwise. We would make another arrangement on selling that if we need to or want to. We would still have very good liquidity even with that remaining cost of the project is almost built. So that's the issue there, Roger.

Okay, I appreciate it. Thanks, guys.

Thank you.

Your next question comes from Leo Mariani from KeyBanc. Leo, please go ahead.

Hi. Good morning here, guys. Just a follow-up on the last comments you made regarding King's Quay. You said that the project is 80% built at this point. So I guess just in the events that this deal doesn't go through, what would be kind of the remaining King's Quay spend that you'd have to put in place in '21? I'm getting the sense it's probably not a lot left here.

I would say that number is probably less than 100. In the 70 range, it's going very well, and we have a team there on the ground today. We are executing that well, and it's an asset that is valuable to sell to someone. I'm not concerned about that, and I'm not negotiating that here anymore, Leo.

Understood. Okay.

We have a lot of flexibility around that. You can see in our debt, in our free cash flow; we almost made enough free cash flow this quarter for that. So we’re doing really well with our operations, really well with our G&A, really well with our LOE, even through these storms, because of our diversity and our other assets are outperforming. We’re very well positioned to take on what we need and these assets where we work, and of course, have plans to handle any outcomes involved with that if we need to.

Okay, understood. And I guess I just wanted to get a sense, I know you guys are talking about restarting the Eagle Ford operating program next year, that's something that hit the ground running pretty early, with a couple of rigs in early 2021. What can you kind of tell us about the way you're looking at tackling Eagle?

Well, we have to keep in mind, we have to meet with our board and approve our budget in December. You know, it's interesting how people tend to do their budgets almost a year ahead; as soon as you do your budget, they start on the next one, which is quite a phenomenon. But to do that, we have ducks to drill in Eagle Ford, probably 14 or 15 of them. I see Eric nodding his head in the affirmative there. We have ducks to drill and some drilling to do, we've got plenty of wells, with about a thousand locations there. But again, that asset is performing very well on the base, that asset is toning in well, at a flatter profile with low maintenance CapEx going forward, a lot of flexibility. And of course, like most operators, I would anticipate a front-end loading of operations in the year. I don’t think that will be uncommon in that regard.

Okay. And I guess maybe just on Mexico; certainly, I think you guys have been talking about a couple wells next year at a minimum. Just trying to get a sense of where you are in that process. I know you've got some partners to negotiate with, but is that something we could potentially see start drilling first half of next year? Or do you think it's more second half? What can you tell us about Mexico?

We're in the middle of discussions with our partners regarding budgeting there, as you can imagine, those conversations are sensitive given these types of prices. I would anticipate it being late next year; we have two very nice, very large prospects there that are coming out of the multitude of options we have, and we’re also very excited about our Brazil wells and the budgeting process with our partner, Exxon Mobil. That will likely be a second-half spud as well. So, nice second-half year type of opportunities there for us as we maintain our diverse business approach.

Okay, that's very helpful. I appreciate it.

No, thank you.

And your next question comes from Josh Silverstein from Wolfe Research. Please go ahead.

Good morning, guys. Just on the King’s Quay transaction here. You highlighted the value of the project completion date. I'm just wondering, flipping this around, given how far along it is, would you actually consider keeping it at this point? It doesn't seem like you want to do that, but could that potentially be on the table?

Really, trying not to negotiate it here, Josh, as I said, we can do that, we can afford to do that. We've decided to go down this road and we've progressed along the way, and we continue to progress that. It’s just a delay in the closing timing so far that has been the issue. Putting out additional dates on that is not helping the matter at all, and we will continue to progress towards the original goal. But we have ultimate flexibility to do anything we need here. But the goal is still to complete it, and as long as we're progressing, we will continue on that path until it no longer progresses, of course, but that's not the case today.

Got you finally. And then I wasn't sure if it was asked a couple questions ago, but as far as the volume guidance and spending for roughly kind of flattish around $700 million year-over-year, what's the breakeven that you guys have on crude oil and gas price? I know there's a little bit of flexibility to shift capital around, but what was the…?

Breakeven in what way, Josh?

Cash flow breakeven.

With dividend or with capital?

Of course, the dividend.

In the low 40s, very low 40s. Below 42.

Okay, thanks guys.

No problem. Appreciate your call.

Your next question comes from Arun Jayaram of JP Morgan, please go ahead.

Welcome in. You’re last one today.

Hey, Roger, how are you?

Doing great.

Roger, wondering if you could give us an update on the development program at Khaleesi and Mormont and confidence in delivering that? Is it first half, is it '22 production outlook?

Yes, well, the facility is going very well. We have experienced people in building and constructing these things. That's something we're in charge of, as an asset that we own and are also the operator. So that's a big advantage for us. The wells that are drilled for Khaleesi/Mormont/Samurai will require some additional drilling. Khaleesi/Mormont is greatly de-risked by six wellbore penetrations and six cached wells. We have the wells or pay on log and have third-party reserves. So we need to get out there and do the completions, which is important to differentiate between completion and drilling permits if we want to have concerns about some of these political matters. We are very knowledgeable and astute about the complexities involved. It's an asset that's set up to perform and advance. We have the rig contracted, which is also important, and the permitting process has become more specific through the years. I'm very pleased with my team, and we are executing well.

Okay. Roger, my second question is just a little bit more maybe a color or clarification on Mexico and Brazil next year. Does the Mexico plan include the Cholula appraisal or are you directly drilling some rank exploration wells? And then you're saying that in Brazil, you could spud a well in the second half of '21?

Yes, that's correct. Well, we're not spudding, our operator ExxonMobil is.

Exxon, yes.

In Mexico, we have a call between ourselves and our partner, Cholula, which is an appraisal program approved by the government there. We do not need to execute on it; we have time or we can drill a larger structure, a larger subsalt structure, which has been de-risked by other wells in that region, presenting a much larger prospect, if you will, that we may lean toward. We're working with our partners now regarding timing and the choice between those two options.

Flattish CapEx guidance, right for outlook I should say.

Yeah, also be clear on the CapEx. For next year, we're guiding a CapEx similar to this year. I think it's trending a little lower than the midpoint of 2020 at this time. The '22 CapEx would be similar, and after that, we expect much lower CapEx and significant free cash flow coming out of this business as the offshore projects come on. So this notion that we'll have that CapEx forever is not the point we're trying to make. '21 and '22 will be the higher CapEx levels by far, absent some incredible exploration success in our business.

Okay, I got one more, Roger, if I could sneak one more in. You did note that most of your debt maturities are in 2024 and beyond. My question is you do have some 2022 maturities, and you've got some time on those, but what is the general thought on addressing those? Do you issue new debt to term those out or where’s your head today regarding those maturities?

Well, while you were talking, Lee or Gail asked that question, and David answered it, but because you're a nice guy, I will answer for you again. David, tell him one more time.

Yeah, Arun. Obviously, we have like $260 million coming due in June of '22 and $320 million or so in December. So, it's certainly on the front of our minds. We, as you know, keep an eye on the bond markets regularly. Bond market today for names such as us is not great. There's been a lot of uncertainty around oil prices and the political climate. We still want to see how that plays out. We’re watching it closely. We’re always prepared to act if and when necessary and if and when the market plays in our favor. We feel like we do have that opportunity if we need to.

Also, I think it's important to note the separation of the notes due in the middle and at the end of the year in a post-COVID world; six months is a lifetime in earnings cycles. It's not like it's due in the middle of the year. This gives us quite a bit of time before the second note comes due, which can easily be placed in a revolver. The key for us is to keep our revolver empty. When that happens, securing another one is very easy. Additionally, Murphy has an unsecured revolver. We've never had any security from our revolving credit facility in our company history, nor have I ever encountered anything like that. We have enormous flexibility regarding our liquidity and our evolving situation, and our long-term positivity in the market regarding bonds and deals we've had in the past.

Got it. Roger, thanks for that. There's a lot more, and I guess that serves me right for getting on this call late. So anyways, thanks for your comments.

No problem, Arun. I'll talk to you soon. I appreciate you.

I would now like to turn the call back over to Roger Jenkins for any closing comments.

I appreciate everyone calling in today. We'll see you at our next call in late January. Thanks for everything. See you soon. Take care.

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