Murphy Oil Corp (MUR) 2020 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Fourth Quarter 2020 Earnings Conference Call. (Operator Instructions)

I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Good morning, everyone. Thank you for joining us on our fourth 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 have placed on the Investor Relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of Mexico.

Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may cause actual results to differ. For further discussions of Risk Factors, see Murphy's 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 Jenkins.

Good morning, Kelly. Thanks to everyone for calling in today. Before we get started reviewing our 2020 and looking forward, second day, I would like to address the recent actions taken by the Biden-Harris administration. Murphy, like all operators across federal lands in the United States, is disappointed, but not at all surprised by recent actions. Unfortunately, as a matter of public policy, we believe their efforts is misguided. U.S. emissions peaked over a decade ago in the United States and continue to fall every year. Growth in worldwide greenhouse gas emissions comes primarily from the Far East, Southeast Asia and Africa. These new initiatives will punish domestic producers and workers, but will not lower worldwide emissions. Ironically, any policy that includes the Gulf of Mexico actually hurts the carbon footprint as the deepwater Gulf has the lowest carbon intensity of all of the E&P business.

Last week, the U.S. Department of (inaudible) (00:02:29) announced a temporary suspension of delegated authority for 60 days. It is important to note that this order does not limit existing operations under valid leases and provides a method for obtaining necessary approvals. There is potential for delay in consolidation of approval authority. However, to date, we have been pleased with the progress and are moving forward.

Murphy is well positioned to continue execution of our short-term and long-term projects, including Khaleesi, Mormont and Samurai and our nonoperated projects based on approvals in hand, discussions with our regulators and progress made in the last week, obtaining actual approvals to conduct ongoing operations on current leases. We've also seen, in the past 2 weeks, over 20 approvals given for work in the Gulf of Mexico to not only us, but our peers. Yesterday the White house announced a pause on new oil and natural gas leasing on federal land and waters, pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. This action is also not surprising. Existing and ongoing lease work was not included in the announcement.

The administration's recent actions have confirmed the viability of our company's strategy and increase the value of our diverse global portfolio. This includes large private U.S. onshore acreage, both onshore and offshore Canada assets and a robust international exploration portfolio, including offshore Mexico, Brazil and Vietnam.

As you can imagine, there are many pieces here moving forward. We expect once the dust settles that permitting approvals will return to a process we can work with. It's not in the government's best interest to halt operations in the Gulf for a host of financial and legal reasons. Again, we have a diverse portfolio, and all these actions are highly likely to increase oil prices, which would be in our favor over time.

That's all I have on this comment today and these remarks, and we'll turn to Slide 2. Murphy remains steadfast in our strategy despite the turmoil of 2020, maintaining our diverse portfolio while operating in a safe, sustainable and physically responsible manner. Our capital discipline leads to a targeted flatter oil production profile, with additional free cash flow generation coming from the recently announced Tupper Montney development, along with long-term price recovery scenario.

We remain focused on our shareholders through our long-standing dividend, our employees, contractors and communities by establishing and practicing of successful COVID-19 protocols. Our portfolio continues to span onshore and offshore locations in both U.S. and Canada, which offers many advantages in today's times. And lastly, Murphy remains a strong company making exploration program on existing acreage in both the Gulf of Mexico and internationally.

Slide 3. Following the OPEC price war beginning of the COVID-19 global pandemic last year, we focused on a few primary areas to solidify the company and remain competitive over the long-term with multi-basin operations. We've completed a significant company-wide reorganization, resulting in reduced G&A costs as well as lowered our overall cost structure and capital program. Our focus on maximizing free cash flow and maintain liquidity with the support of crude oil hedges and natural gas forward sale contracts led to the sanctioning of the low-risk Tupper Montney development and reduced capital allocation toward growing shale oil production. Additionally, we continue to support development plans for both long-term deepwater Gulf projects as well as our international exploration program.

Slide 4. Murphy produced an average of 149,000 barrels of oil equivalent per day in the fourth quarter. These volumes include impacts totaling nearly 4,000 barrels equivalent from 2 subsea equipment issues with production expected to restart in the first quarter 2021. The unplanned events in the Gulf of Mexico were partially offset by strong North America onshore performance. Our cash CapEx totaled $111 million for the quarter, inclusive of $1 million in NCI spending. On an accrued basis, CapEx totaled $130 million net to Murphy, excluding King’s Quay. Prices continued to improve in the fourth quarter with oil realizations at an average of $42, the highest, of course, seen since quarter 1, and natural gas at $2.36 per 1,000 cubic feet, also far ahead of prior quarters.

On Slide 5. Our full year 2020 production averaged 164,000 barrels of oil per day. It’s a dynamic year and we experienced a record-breaking hurricane season following historically low prices resulting in industry-wide production shut-ins for a short period. Overall, for the year, we averaged nearly $38 per barrel for realized oil prices with $1.85 per 1,000 cubic feet for natural gas. Cash CapEx for the year totaled $760 million, which included $23 million of NCI CapEx. On an accrued basis, CapEx totaled $712 million, excluding King’s Quay and NCI spending as per our guidance.

On reserves on Slide 6. Our proved reserve base remains sizable at year-end 2020, with 697 million barrels of oil equivalent, comprised of 41% liquids and 51% proved developed. Approved reserve life is maintained at more than 11 years. Overall, our total approved reserves were 13% lower from the year-end 2019 due to 2 primary events. The first was a combination of lower SEC crude oil prices along with Murphy's shift and focus away from oil shale production growth, which resulted in transfer of Eagle Ford Shale and Kaybob Duvernay PUDs to probable reserves. The change in capital allocation over the current 5-year plan reduced PUDs by over 100 million barrels equivalent. Separately, the sanction of the Tupper Montney development in the fourth quarter resulted in the conversion of probable reserves and contingent resources to proven undeveloped, totaling nearly 100 million barrels equivalent.

On Page 7, while total proved reserves were lower year-over-year, our North American onshore approved plus probable resource remained near 2.5 billion barrels of oil equivalent. We maintain the ability to rebook our onshore shale PUDs with adjusted capital plan in the future if we decide to do so. As the reserve transfers, we're based on capital timing and not subsurface risk. As in any resource booking, it would also depend on prices, cost structure at the time and a 5-year planning cycle change. Overall, Murphy continues to hold more than 3,400 undrilled locations across onshore North America. Further, our U.S. onshore Eagle Ford Shale position is located on private lands.

I'm now going to turn it over to David Looney, our CFO, and let him update us on some financial information. David?

Thank you, Roger, and good morning. Slide 8. Murphy recorded a net loss of $172 million or a $1.11 net loss per diluted share for the fourth quarter of 2020. After-tax adjustments, including, but not limited to, a noncash mark-to-market loss on crude oil derivative contracts and contingent consideration, totaling $159 million resulted in an adjusted net loss of $14 million or a $0.09 adjusted net loss per diluted share.

Slide 9. Improving commodity prices led to further strengthening in revenue for the quarter. Overall, our net cash provided by continuing operations rose to $225 million in the fourth quarter, including a $13 million cash outflow from a working capital increase. When combined with property additions and dry hole costs of $135 million, including $38 million for King’s Quay, we had positive free cash flow of $90 million in the quarter. Regarding King’s Quay, the producer and owner groups continue to make good progress on the array of legal documents, and we look forward to a closing possibly within the next few weeks.

For full year 2020, our net cash from continuing operations of $803 million included a $39 million outflow from working capital. Property additions and dry hole costs of $859 million, including King’s Quay spending of $113 million, resulted in a negative free cash flow of $56 million for the year. If we exclude the King’s Quay expenditures for the year, we would have had positive free cash flow of more than $55 million.

We continue to maintain a high level of liquidity with $1.7 billion at year-end, including $311 million of cash and equivalents at December 31. With our focus on cost reduction measures throughout 2020, we've achieved significantly lower G&A, with an approximately 40% reduction in full year costs from 2019.

Lastly, Murphy continues to protect its future cash flow with the addition of '21 and '22 crude oil hedges as well as fixed price forward sales contracts for a portion of our Tupper Montney production through 2024.

Slide 10. Liquidity remains a key focus for Murphy, and our balance sheet remains strong with $1.4 billion available under our $1.6 billion senior unsecured credit facility as well as $311 million of cash and equivalents as of December 31. We reiterate our goal of reducing our total debt level over time with excess cash flow. This reduced leverage will give us even more resilience through the inevitable commodity price cycles to come.

With that, I'll now turn it back over to Roger.

Thank you, David. On Slide 12. As a company, we're responsible to the environment, employees and our stakeholders. We have a long history of protecting all in part due to our strong internal governance processes. I'm particularly proud of how quickly the team established COVID-19 protocols to maintain safe offshore operations. We have zero downtime or disruptions due to those efforts.

Murphy achieved another year of low metrics, including 46% reduction year-over-year in total recordable incidents. We expanded our internal diversity and inclusion practices and programs, and maintain a program to aid impacted employees in times of need through our Disaster Relief Foundation, which we used this summer with hurricane relief on the Louisiana Coast. Our operations team continued their work on minimizing our environmental impact, such as building a new produced water handling system for recycled water in our sanctioned Tupper Montney project as well as utilizing bi-fuel hydraulic frac spreads on all well completions in Canada, which results in considerable CO2 emissions reductions. While smaller changes individually, they add up to a larger impact over time.

On Slide 13, on sustainability. Last fall, we released our 2020 sustainability report, which features expanded disclosures and metrics. A key highlight is our goal of reducing greenhouse gas emissions intensity of 15% to 20% by 2030 from 2019. The report also outlines diversity disclosures workforce development, employee engagement programs. Murphy has also expanded our HSE Board Committee to include oversight of corporate responsibility formed, and we formed an ESG Executive Committee and created a new Director of Sustainability role. We've taken many steps and we continue to evolve and advance our sustainability efforts.

On Slide 15, on the Eagle Ford Shale business, we produced 31,000 barrels equivalents per day in the fourth quarter, comprised of 71% oil. For the full year, production averaged 36,000 barrels equivalent per day, with $197 million of CapEx, which includes near $50 million for field development as well. We brought online 25 operated and 10 nonoperated wells earlier in that year.

The team continued their efforts on improving well performance and high grading production enhancing projects, especially, our artificial lift optimization. Murphy is seeing an average base decline rate of 24% for all wells drilled prior to '21, which, in our view, is very well positioned.

On Slide 16, on the Kaybob Duvernay project, the company produced 10,000 barrels equivalent oil per day in the fourth quarter, comprised of 75% liquids, and averaged 11,000 barrels equivalent per day for the full year. Overall, Murphy spent $94 million in CapEx during the year, including Placid Montney, breaking online 16 operated wells in Kaybob and 10 nonoperated wells in Placid.

Also in 2020, Murphy completed its drilling program to hold all acreage, resulting in full discretionary future development. Most notable in the second quarter in the Kaybob East 15-19 Pad, which is achieving significant results as our best well in Kaybob Duvernay so far, ranking in the top 2% of all Murphy unconventional wells. Overall, it's competitive with our top producing wells in Karnes County in the Eagle Ford Shale.

Slide 17. In the Tupper Montney, we produced 234 million per day in the fourth quarter and averaged 238 million cubic feet per day full year 2020. Approximately, $14 million of CapEx was spent during the year to drill 4 wells with completions planned this year and ongoing.

Additionally, the Tupper Montney plant expansion was completed during the fourth quarter. Since our last earnings call, Murphy has added significant fixed price forward sale contracts at AECO Hub through 2024, which, combined with improving basis differentials and higher prices as well as higher EURs, can lead to stronger free cash flow generation.

Slide 19. In the Gulf of Mexico, our assets there produced 63,000 barrels equivalent of oil per day in the fourth quarter, comprised of 78% oil. Production volumes were impacted by nearly 4,000 barrels of oil equivalent per day on unplanned downtime due to 2 subsea equipment issues, in addition to previously guided hurricane downtime in the fourth quarter.

Full year 2020 production averaged 70,000 barrels equivalent per day. Short-term projects continued to progress with operated Calliope on schedule for first oil in the second quarter, Nonoperated wells in various stages of completions and tie-ins, and we expect oil to begin flowing in the first half of the year to plan.

In the Gulf of Mexico, Slide 20, on major projects. We remain on schedule with King’s Quay construction at 90% complete and drilling beginning in the second quarter for Khaleesi, Mormont and Samurai development. The nonoperated St. Malo Waterflood continues to move forward with completions on the first producer well underway and preparations being made for drilling a second injector well as well as beginning of a producer well workover.

On Slide 22. In exploration, we participated in the latest OCS Gulf of Mexico lease sale during the fourth quarter, and we were awarded and fully awarded 8 blocks with 5 prospects at a net cost of approximately $5.3 million. As a result, our Gulf of Mexico interest today totals 126 blocks, spanning more than 725,000 acres with 54 exploration blocks and 15 key prospects at this time.

On Slide 24 on our capital program. For 2021, Murphy plans to spend $675 million to $725 million and achieve production of 155, 000 to 165, 000 barrels equivalent per day. For the first quarter, we forecast production of 149, 000 to 157, 000 barrels of oil equivalent per day.

Approximately 47% of our 2021 CapEx is allocated to offshore Gulf of Mexico, with nearly all dedicated to the major long-term projects that achieve first oil in 2022. Another quarter of our 2021 CapEx is budgeted for the Eagle Ford Shale, with the remainder split between onshore Canada and exploration. Overall, we continue to focus on high-margin assets in our oil-weighted portfolio, resulting in free cash flow generation after our dividend.

On Slide 25. Our North American onshore capital budget is $265 million in 2021 and is focused on maintaining flat production in the Eagle Ford Shale, with $170 million dedicated to bringing on 19 operated wells and 53 nonoperating wells as well as field development, which is 30% of the total spend. Approximately $85 million is earmarked for newly sanctioned Tupper Montney development program to bring 14 wells online during the year. The remaining $10 million of CapEx supports field development and maintenance in the Kaybob Duvernay and nonoperated Placid. Of note, our oil-weighted shale assets maintain a long runway of drilling with more than 1,400 locations in the Eagle Ford Shale and more than 600 in the Kaybob Duvernay.

Slide 26. In the Tupper Montney project, we're excited for this opportunity that the development brings to our portfolio. We're seeking -- we're seeing lowest basis differentials in 5 years. Beyond that, we have continual improvement in Murphy's well economics and EURs in the area, creating sustainable attractive cash margins for an asset that also generates the lowest greenhouse carbon intensity in our portfolio. Lastly, the macroeconomics have shifted significantly in our favor in the last few years with additional takeaway capacity, achieving necessary debottlenecking work, both in the West and East ward boundary pipelines as well as construction beginning on LNG Canada project with the planned in-service date of 2025.

On Slide 27. The Tupper Montney asset has been strong proven resource with rising EURs in recent years and ever-improving cost structure, while maintaining very low subsurface risk. We've recently put in place additional fixed price forward shale contracts in 2024, thereby protecting future revenue for the project and assuming cash flow generation. The asset generated free cash flow of approximately $50 million in 2020, which is more than sufficient to cover the cash flow requirements in the next 2 years as the development is initiated. Overall, the current sanction plan requires an average annual CapEx of $68 million and will generate cumulative free cash flow of approximately $215 million through 2025.

Slide 28. In the fourth quarter, we farmed into an attractive play opening trend for a 10% nonoperated working interest with Chevron as operator. The first well plan is a Silverback prospect, and we will provide access -- and we will also be provided access to 12 blocks through our participation.

On Slide 29. We continue to progress our various exploration projects and are excited with the optionality of the nonoperated position in Sergipe-Alagoas Basin in Brazil provides our company. Murphy is working with partners to mature our drilling inventory and our partner plans to spud the first Brazil well in the second half of 2021.

In the Salina Basin in Mexico, on Slide 30, continue to advance our position there. We have many leads and prospects here and target spudding the first exploration well in late '21 or early '22.

Overview of the LRP on Slide 32. Our long-term strategy of a dynamic plan to maximize cash flow while managing CapEx after dividend remains unchanged, as is our commitment to a flatter oil production profile. Our Tupper Montney development leads to an approximately 8% CAGR from '21 through '24, while oil growth remains at 3%. Through this, Murphy will generate cumulative free cash flow after dividend at our base price scenario with significant cash flow achieved in the mid-50s oil price recovery scenario, which will achieve a sizable debt reduction.

As we began with our announcement in 2020 for a lower capital program, the average annual CapEx through 2024 is approximately $600 million, with 2022 being the peak year due to finalizing the major Gulf projects along with increased Tupper Montney development. Of course, we maintain a portion allocated to exploration strategy with a target of drilling 3 to 5 wells per year.

Slide 33 is to close out 2020 and lean into '21. Murphy is sticking with our priorities of managing CapEx to support a flatter production profile, when combined with protective hedges, allows for maximum free cash flow generation, strong liquidity and debt reduction and long-term price recovery as well as consistently paying a dividend to our shareholders.

Lastly, I want to extend my sincere gratitude to all of our employees for their efforts throughout 2020. And with their dedication and our new plans, we are well positioned heading into '21.

I'll now end my remarks today and be glad to turn it over for any questions anyone may have. Thank you.

(Operator Instructions) First question comes from Neal Dingmann at Truist Securities.

Roger, I appreciate your prepared comments on the federal leases and permits. I'm just wondering if I could dive straight into that. Could you give your thoughts on, just in ballpark, how long you anticipate that your current inventory could take you? And more specifically, what you all would eventually pivot towards if there was some type of ridiculous permanent federal band or -- and once your current assets are worked out?

Well, actually, as I said, there's short-term and long-term things that we work on every day in the business. It's a business that requires communication with the regulator across several factors. We've continued to be able to do that during the suspension of authority period. We're very pleased with that. Also pleased with what's going on with non-operated work on a day-to-day type basis, which -- in our remarks today, we talked about some subsea wells that are needed to be repaired, and that work is progressing as per even with this suspension.

We're well positioned to start our Khaleesi-Mormont project and continue on. Actually, we are ahead of target on regulatory there, and have more permits than you would normally have for development this time. The permits are given pretty close to the drilling date and historically been that way in the Gulf. So well positioned there.

As far as a -- what would we do with some kind of scenario like that, I mean, I appreciate that question. But yesterday's executive orders did not mention anything about current leasing. We're finding that everything that's ongoing, like our project is being treated like an ongoing project. And that's the way it's being treated and being worked today. There's regulatory work going on in a normal business basis today in this building.

And so -- but naturally, if there were to be some wild outlandish moratorium, which didn't do well in the Macondo time for the government at all, we have a lot of flexibility. First step may would be, hey, let's just stop and have a lot more free cash flow and pay down our '22 notes with this matter and then continue on. There wouldn't be a need to rush in to go try to duplicate things that we own, that's kind of our first step. And it's quite helpful to us in that regard if we're able to get these projects back going again. Naturally, we have a big business in the Eagle Ford that can be throttled and changed because oil prices in any kind of moratorium like that with the Gulf, making almost 3 million barrels a day would make that much more attractive. Our Canadian business is doing extremely well. Our Canadian regulations continue to be very supportive. So a lot of things for us to do to replace the production if we want to, with the capital efficiency and much higher oil prices. But in all-in all, it's a pretty wild scenario. And the work that we're doing today isn't pointing to that scenario in my view, Neal.

No, I agree with you. And then just my follow-up, I'll stick with the Gulf. I'm looking at that Slide 22, and it just really reemphasizes just how many opportunities you have there. Just wondering, Roger, what gets you -- you have so many of these things when I'm looking at all the exploration projects, as you mentioned, prepared remarks, a number of things coming on, not even this year, but already planned for next year. I'm just wondering, what sort of makes you most excited right now when you look at all these projects in the Gulf? Are there a few that you would point us to or -- I'm really curious on how you would think about it. I want to hear your angle on it.

Well, we built a new area on the slide in that OSO area, that's where we have Rushmore and OSO and gilder. That's a new area for us that we're very excited about. We feel that we're seismic advantage in that area. We also have a couple of opportunities near Front Runner, Ninja that we're happy about because it's nearby. We have a very exciting well to drill at Cascade, Chinook in the long run. It's a down thrown fault segment -- down thrown fault segments in most major Wilcox plays have been very successful. It's a very big deal for us in the future, a very large type of a well that's near production.

And we're very happy to partner with Chevron in our new Silverback area, which is adjacent -- as shown in the slide here, adjacent to some acreage that we also feel has that same new feature, we're very excited at Chevron, again, back to our strategy of being a respected company that people want to work with. We're fortunate to be in a working relationship with a super major that respects our ability and our knowledge and our experience, and our long-term experience in the Gulf. So I feel really well positioned because that's sort of a company making thing at the right kind of working interest, but helps us derisk our blocks if that were to be successful. So those are the highlights there, Neal.

The next question comes from Dun McIntosh at Johnson Rice.

I noticed on the Eagle Ford spend for next year, $170 million, but a little less than 1/3 of that is going to be going towards what you call field development. Hoping you could provide a little more color on what you're going to be building out there.

I'll have Eric get his expertise and talk to you all the way through that and everything you need, right here.

Okay. When we build our capital program, what we lump into field development is pretty much everything other than wells. So building pads, flow lines, pipelines, allocation, separators, people costs, things like that. So it seems like a large number, but it really is more driven by the well activity. It's not like we're building a massive new facility.

We're also working on electrification, some other things involving ESG in this business all the time on improving our flaring and reducing always our emissions. We have a new takeaway of pipeline in the Eagle Ford to further reduce flaring that we're excited about. So there's CapEx took in those types of things as well that are required and needed, and the right thing to do at this time.

All right. And then for a follow-up on the Tupper Montney, congrats on getting that 10-well program sanctioned. But looking beyond that kind of longer-term, with the 6% gas CAGR versus the -- or 8% versus the oil over the next kind of 3 or 4 years, what are you all seeing up there that you think might be stickier, maybe from a demand perspective? I know you said basis has gotten tightened up the most it's been in 5 years. Just kind of looking for some color on what you all are...

Yes. If you look at the data, it was very variable on a very poor basis, very poor, of which we did some off AECO type business to protect our risk, which worked very well for us at that time. Then the debottlenecking by TCPL claim they were going to do all this capital work. They did the work, both East and West. And there was a time where it was difficult to get the gas to a summer storage facility there. And now that they're needing more gas in the country and less capital available by Canadian junior players in Calgary, then the production has greatly dropped. And now we can get the gas to storage, which eliminates this very viable, very, very low, poor summer months type productions and shut ins.

Also, TCPL had downtime through the years, quite frankly. And because there's less 2 Bcf of less production, there's less downtime. So here we are with this big position, best, lowest risk thing we ever have. We started comparing it to low oil prices. And then we decided this would be a great capital allocation for us, also very, very good from a greenhouse gas intensity perspective. So we feel there's a better chance for oil to go to $60 and make a lot of cash flow in our oil flat production shale than it is for gas here to get at $5, let's say. Then we found a unique way to book the gas and hedges that was very advantageous to us and allowed us to almost book, if you will, free cash flow. Also, these reserves are audited -- completely audited by McDaniel's in Canada and have been for a long time.

Eric is a former executive involving reserve auditing. So we have the top of the line reserve work here, great operations, incredible -- ahead of it, hedging that we've done and really well positioned in there that's happened over time. Also, in Canada, they have switched co-out and have less production and need the gas when we get to storage. And we have LNG long term there, which we are, of course, very familiar with in Malaysia. And offer -- and a lot of those folks involved with LNG we've worked with before and our outstanding reputation to deliver gas in Canada -- I mean, in Asia over these years through LNG will help us there in the long run, in my view.

The next question comes from Leo Mariani at KeyBanc.

Just wanted to follow-up a little bit on some of those last comments. If I hear you right, it sounds like you guys are much more bullish on gas than oil over the next couple of years. And maybe just kind of doing a little bit of a look back, just on third quarter, you guys were certainly planning on kind of ramping up Eagle Ford here in '21. When I think some higher expected volumes when oil prices were closer to 40%, and now we're kind of over 50% here today on oil and gas maybe hadn't done all that much in the last several months.

It's a little bit better, but not as dramatic of an improvement. I understand you guys had facility work, and there's a lot more capacity now at Tupper and summer outlook looks better. But just wanted to kind of confirm, are you just more optimistic about gas in the next couple of years versus oil? And does it just looks like to you that the returns are tougher or just better now than Eagle Ford, despite higher oil prices?

Well, it's not at all that way as far as the bullishness to oil. We still feel oil can go up and especially with all this regulatory. But what we're trying to do and what we said was to -- we want to plan our business on a flatter oil profile in Shale, especially Eagle Ford. And because we're well positioned there with our high oil percent and very known customer in that area, selling of our oil is needed in that area. We feel that if we keep that flat and oil prices go up, we can make much more free cash flow.

And we're trying to get out of the debt business and add free cash flow and successfully handle that. Also our folks in the Eagle Ford have done a great job on maintaining base and base decline, which I think is very critical. So it's not that way at all. We see as an increase in oil price as a way of keeping shale flatter and making more free cash flow, which is not uncommon supposedly by my peers.

Now in Canada, price has been greatly improved, our cost structure improved. We had like 15 different reasons why we needed to book that and do that. We're still only going to be making at -- when this project's full-out around 500 million a day. So it's not like we're turning all gas and making Bcf of gas or anything like that.

So it's all about, as we said before, a flatter profile with more free cash flow to significantly reduce debt and higher prices. Then the Montney came along on top of that, and you have to say for a project that's going to go from $240 million to $500 million and fooling around with $80 million CapEx to do that really isn't that difficult and it's very capital efficient.

So it's more about a unique project that we have was in our face to be successful with our flat profile with higher oil prices to have more free cash flow. It's that, it's nowhere around anti bullishness on oil prices or anything like that, Leo, really.

And obviously, you guys talked a little bit about your multiyear ramp at Tupper, kind of 8% between now and 2024, pretty robust. You guys are talking a little bit more kind of flat to 3% on the oil side. Just how does the Eagle Ford participate once we get out of '21? And it looks like you're trying to maintain Eagle Ford in '21 at fourth quarter. Is there a ramp in '22, 23 or '24 or are you going to basically wait after King’s Quay comes on to kind of reallocate CapEx? What's the long-term plan for the Eagle Ford here?

Our plan today is, again, to have a flat profile in the Eagle Ford to set it up to make -- it could probably make $500 million to $600 million free cash flow over a 4- to 5-year period in 50 -- mid-50s oil price. And that's what we wanted to do today. That's our plan today. And it doesn't really have to do with King’s Quay or anything like that.

So again, our strategy, as you know, from most of last year was as planned. It just so happens that the Montney got so positive for us that we added it on with very little change in CapEx. And it improved all -- it was accretive to all our metrics, our covenant metrics, our free cash flow metrics. It was accretive to everything we did, so we executed on because our cost structure is so low. It's really that, Leo.

Okay. No, that's good color. Maybe just on the Gulf of Mexico here. You guys talked about fairly significant downtime in the fourth quarter. You talked about some downtime moving into first quarter as well. Can you kind of quantify what's baked into the first quarter guide in terms of the downtime here?

I was just kind of looking at your guidance, and I think you guys are saying your oil volumes are going to be up around 3,000 barrels a day in the first quarter, despite the fact that you had something like 18,000 BOE per day down in the fourth quarter through storms and whatnot. So I guess, I'm just trying to figure out there's a bunch of additional downtime in the first quarter. I would have thought it would have been up more.

We were well positioned going into around mid-December in the Gulf, and very, very well positioned. We had 2 one-off subsea events happen that require some equipment to be put offshore and repaired. One was an operating field and one non-op. That is in works now to be done on both at different levels of completion, and we have that in this quarter to be recovered.

We also have some very nice wells being drilled at Lucius, operated now, of course, OXY that we purchased through the Petrobras agreement, through that formation of a JOA. And so that will be coming online, and it's -- we will be increasing production in the second quarter in the Gulf with all that. And that's where we are on that, Leo. It was a surprise, a couple of subsea events are being fixed. And we have wells coming on at Lucius as well. Also, our Calliope well that we mentioned, and doing well.

Our next question comes from Arun Jayaram at JPMorgan.

Roger, I wanted to ask you about the 2021 to '24 outlook that you've highlighted on Slide 32. You guys have provided an outlook of $600 million in CapEx per annum, with a little bit of higher CapEx in 2022 with development projects. I'm wondering if you can maybe help us think about the year-to-year trajectory from '22 to 2024?

Arun, if I wanted to give you the year-to-year trajectory, I would have put it on the slides. I have it right here in my hand. In 4 years, we've seen 2 major price collapses in our business and recover back and guiding out year-to-year CapEx. I don't think it's a good idea. There's no secret that our CapEx this year, midpoint of $700 million, is what it is. And I think very well positioned to do what we're doing with that, with all the money that we're spending that will not contribute to oil production of shale or gas.

And next year is going to be higher OpEx than this year. And we're going to be dropping down pretty drastically after that. So I prefer to leave it at that right now. A lot happens in a year, but that's our plan and through the color I provided on the prior calls, about the flatter profile and more higher oil prices align more cash flow. That's our plan.

But we -- I think the point here we're trying to make is that we've disclosed the CAGRs. We have our business that we talked about, our oil business, if you will, our offshore business, our Eagle Ford business and the Duvernay, of course, is almost 80% liquids business with very, very high prices and doing well. That business is slightly growing, which has been our plan for 9 months, probably. And the growth is in the Montney because it's time getting into the Montney and booked that and it was available to us.

So through that, though, with conservative oil prices through this 4-year period, we will have cash flow cumulative above our dividend. In the low-40s or mid-40s at most. And in the mid-50s, we're going to -- we can cut our debt and high for more, and that's what we're trying to do. Working on it.

Fair enough. And my second question is just regarding the Gulf of Mexico development program. You guys were sticking with the timeline around Khaleesi, Mormont, Samurai first oil. Based on what we know to date, Roger, and stop me if I'm wrong, you've received 2 of the 10 permits for the program at Samurai, number 3 and number 4 per IHS. Can you walk us through -- and I think the rig arrives in April, but do you get started at Samurai and just wait for the incremental permit approvals? And do you think that we could see some permit approvals in this 60-day time out from the DOI based on some of your commentary that you mentioned earlier?

Thanks, Arun, for that. It's nothing -- I don't know where the 10-well thing is coming from. We have a 10-well commitment on a rig to do any kind of work we want for a certain price in the Gulf of Mexico. This is a 7-well Phase I development. Phase I, meaning for the next few years. I think there's another couple of wells beyond '23 or something like that.

There's 4 existing wells in the ground out there. They've been drilled in are cased and log everything. There's 3 wells. When I talk about this, it's Khaleesi, Mormont and Samurai, which we work as one continuous field. We have partners that are different in those that not matter at this time.

4 existing wells, 3 new wells to be drilled and completed. So you're correct. On a public website, we do hold 2 drilling permits today. You can't get the completion permit to the wells are drilled. Completion permits often lag drilling permits because the drilling permit is a lot more complex and has been. It's nothing new, all the proper documentation. So it would be not the norm at all to have all this approved, and I think we're well ahead to have what we have now because we are starting to work in April.

And I'm not going to comment on the permits we get. They know we don't need them with our schedule, if you will. They know where the rigs are. They run the business, they regulate the business. We have a great relationship with the regulator. Also, we're a very, very good operator in the Gulf and carry a great standing on spills. We haven't had a spill in the Gulf in over 4 years, a great safety record, an incredible record as to instance of noncompliance. We're one of the leading companies, so I believe that all helps.

And like I said, we're well positioned here. And I would not have -- now we have submitted all these permits. And as a matter of fact, the completion permits have been -- come back to us for comments. It's quite often to ask questions on these permits. So they're engaged in an ongoing field in an ongoing way and there's documentation also. When you start a development like this with the government to outlay to them that you're going to develop this and you have to provide that you've got a signed rig contract and the signed ability to put in the pipelines. And they're part of an overall process that they know about, and we are relying on and they know this. And so it's going as we would anticipate. And we, like I said, based on -- it's only one week, but based on what we've seen, we're working with it and moving our business forward.

Your next question comes from Brian Singer at Goldman Sachs.

To follow-up further on the Tupper Montney gas. You indicated you've gotten the EUR up to 21 Bcf. And I wondered, a, is that a function of the longer laterals or can you add more color on what's changed beyond that? And then, b, is that kind of the going forward expectation for wells and is the 11,000, the expectation for lateral length on a longer-term basis.

I'll let Eric counter that for you, Brian, and I'll come back to any other question you might have.

Brian, the well performance is driven by 2 things: longer laterals and also better recovery per lateral foot or lateral meter. So if you go back to the beginning of our asset there, we had 4 Bcf wells that were about 5,000-foot laterals. And now we have 21 Bcf wells that are about 11,000, 12,000-foot. Our plan is to have about 3,000-meter laterals for this development program. And so you're getting a combination of improved performance per lateral foot plus longer laterals. Going forward, we don't expect to lengthen our laterals from what we've been doing over the last couple of years.

Great. And then my follow-up is with regards to Slide 32, the slide that focuses on that 2021 to 2024 plan. Can you talk a little bit more about what's baked into that? Is there a wedge at all baked into either CapEx or production, assuming any exploratory discoveries from here? Is there any kind of risking on federal land, timing and timing of projects? And can you talk about Vietnam and whether there's anything there that's baked in from either a CapEx or production perspective?

There's absolutely no exploration success in the plan. It never has been. And that's why this talk of delaying and permitting really doesn't do anything to our company. And as we talked about earlier, we have 15 really good prospects in the Gulf on acreage that we hold. Entered into another project with a super major with acreage that they hold today. And again, the executive order yesterday didn't really get into that. Vietnam is a field development that is absolutely in place. It's between 80 million and 100 million-barrel project. It can be developed.

We've submitted the field development plan and working with the regulator there. It's -- we're used to working with regulators offshore all over the world. And projects, it's about the same. As a matter of fact, people are not realizing this, but most international areas copy the U.S. regulatory. We're very used to it. And -- but it's a little slower there for that. And when they get that, we could put that into our plan and look at replacing something.

But today, it's not in the plan. This is what we own today, what we're doing. We're very knowledgeable about it. We do not have a delay built in on Khaleesi, Mormont, Samurai, nor St. Malo. I feel comfortable with what I understand about the projects, not to do that at this time. I'd say we're ahead of schedule on Khaleesi, Mormont and Samurai, which gives us better flexibility. If anything, we're ahead there. So in that position and the schedule would allow for flexibility in my view based on what I know today, this way I feel by, Brian.

The next question comes from Gail Nicholson at Stephens.

I was curious on the farm-in opportunities. I feel like people don't fully appreciate your track record and the interest that you guys garner in that. Can you just talk about how that farm-in opportunities have changed over time and what you kind of see potentially in the future there?

Well, there are not many operators in the Gulf at our size and nimbleness, if you will. And we have -- we've been in the Gulf for a long time. We're a top 4 operator on gross operated production in the Gulf, well known. All of our executive team primarily worked super majors before. We have relationships with super majors. We are respected in that way. And there's a lot of opportunity.

And this idea about leasing and leasing could be delayed or no future leasing that we have 54 exploration blocks ourselves. Can you imagine how many BP, Shell and Chevron have? And going forward, there's been no mention of stopping that at this point. Could be, but it hasn't been that way. We will be able to look at all kinds of things in the Gulf going forward, the way the regulation and executive order is at this time.

The issue with some of these things, it's a very nice thing here. It is a rank opportunity and a new play. But all my friends really don't like me to talk about it too much. So the more -- the better and better things I do, my operator friends don't like me to speak about it. So I'm caught up in that a little bit. And I'm not going to blow that because I want to keep those relationships and continue to farm into these very unique company-making opportunities such as silver back, such as Silverback, such as Sergipe-Alagoas and other places where we work.

So sometimes that slide wouldn't show what exactly we'd like to say. But that's the business we're in, and that's okay. And we get along with them well, and there's a mutual respect by super majors with our company, and we're proud of it.

Great. And then just looking at the Montney, you guys have a very impressive all-in cost up there about $1.44 per Mcfe. I was just kind of curious, as you move into a more steady state development program, do you think that there's room for incremental cost improvement over time?

I'll let Eric answer that for you, Gail.

I have a significant percentage of our operating costs that are not variable with production rate. So as we fill the gas plant, as Roger mentioned, we'll get up to about 500 million cubic feet at the peak in that project. We'll see the per barrel or per Mcf costs go down. So I would model the cost to be in terms of dollars per year, nearly flat, maybe slight increase with a little bit more cost for new wells, but very minor.

Next question comes from Paul Cheng at Scotiabank.

I wondered that -- just curious that in your budget, I suppose that you have a range of oil price you build in. Can you share with us what's that? And how this may change based on the changes in oil price? If oil price is much higher than that range or you are pretty much fixed to that and say, okay, if the higher oil price are just going to generate more free cash flow, so how should we look at that program?

We don't usually disclose our pricing. We have here a base price that's over the next 4 to 5 years, I'd describe is at best mid-40s, starting low to mid. We have a recovery case that reaches into the 50s and 2, 3 years, mid-50s, never more than that.

It is our plan today to not increase this CapEx. And to have the higher oil prices, deliver more cash flow to our company, balance sheet to be used as we see fit to reduce debt at the appropriate and proper time. So no discussions here on a different capital plan on anything like that today, Paul, going on here at Murphy.

Perfect. And for Montney, it's really a great economic. So right now, your plan is get to 500, but you do have a lot of inventory. So is there any plan or any opportunity that to expand that beyond that? Have you talked to the gas plant operator and see whether that is going to see more infrastructure being built?

We have a unique agreement when we sold this business for this -- for that provider of the midstream work to build plants at a fixed price or a way of negotiating a price, which we considered to be well positioned. We did that here, and there's ample area to do it. It can be -- it can continue to go in 250 million increments as much as we want there.

Right now, we're going through a '24, '25 period of keeping it 500 in our current plan and then reevaluate if we want to go more, but we certainly can. And if I wouldn't see us increasing it in this plan because, again, of all the talk this morning about trying to keep our plan like it is and make more free cash flow. The real unique thing about Montney that may not be understood is our -- is that infrastructure is in place. It's been very successful this plant from an uptime perspective. And they built a twin to it, if you will, next door. And all the infrastructure roads, ponds, they do very well on water capture here, water recycling. This is in place, and we're drilling right in the middle of where we've already built the infrastructure. It's extremely capital-efficient here and very unique.

But we needed -- we were doing really well on all our work, but the price just changed, the (inaudible) (00:53:40) just changed. Everything changed, and we see that you have to make a move, and we had a great plant and a great midstream operator. It's going extremely well. We moved on and went ahead.

Roger, how does that pose have work in terms of the -- let's say, who make the decision going to expand the plan as a midstream operator or that you guys make a request and then sign a contract with them, they will increase it or that you sold it from there?

No. We'll have to mutually agree on the next one to work, and we will, and I can't imagine why they wouldn't want to continue because their subsurface seems a bit low and we're a nice capitalized company for them to be partners with.

Two final quick questions. First, that for the December and planned downtime in the Gulf of Mexico, is that fully fixed the problem? And what is the...

No, they're both...

impact in the first quarter.

Boats in the field, working on the problems today or this week and the impact of that -- it's already in our guidance as to when we think the wells will come back on. And do you know the impact, Eric?

Middle of the quarter.

Middle of the quarter should all be flowing, and it's in our guidance.

And so we should assume it's roughly about 5,000 barrels per day?

No, it's not that much.

We're trying to look at what is the incremental benefit that in the second quarter we should assume when it's coming back?

It's in the plan. It wouldn't be that -- it's not that much. The first quarter current guidance would not be that magnitude of downtime from these wells, probably be about 3,000 off the top of my head.

Okay. And then finally that you already have a pretty sizable hedging program for 2021. Should we assume you're pretty offset or that you will look for opportunity to increase that further?

In '21, no, at this time. In '22, we have done some hedges, which is disclosed in our release, and working on options to review that, but not settled in on that now because we feel like we're well positioned with our cash. We feel like we're well positioned on our liquidity, and really taking a look at the additional hedging for '22 at this time and haven't made a decision yet on that.

(Operator Instructions) Next question comes from Josh Silverstein at Wolfe Research.

I'll just follow-up on the -- some of the hedges there. You've mentioned the $47 number this year to cover the CapEx and the dividend. I'm wondering if that excludes the hedges since those were put in place at $43. And then maybe if you can just give us some trajectory in that longer-term outlook. I imagine the $47 may go higher next year since it's a peak spending. But then where would that go to in the '23, '24 time period as the bigger projects fell off?

Our number here would include the hedges and all calculations. And the follow-on question -- I'm sorry, in the future, we have some '22 hedges that's disclosed here today. That's all we have, and I have no hedging done prior to that. We do like to hedge some of our production. It depends on how much free cash flow and where oil goes and where our liquidity is as to that percent that we would want to do. Historically, have not been that high of a hedger, but reviewing that in the detail. Does that answer your question, Josh?

Yes. Sorry. The second part of it was just the trajectory of where the $47 may go to next year. My guess is maybe it goes up. But then as you go into 2023 and '24, where would that $47 fall towards?

Well, I wish I knew that. I wouldn't be here talking to you. So I believe, myself, there's not a lot of liquidity. We're in backwardation now severely, we have seen periods of time before COVID, where the backwardation just continues to move to the right and the curve looks the same. We're -- like I said earlier today, we have a base price of low 40 to mid-40s over a '20 to '25 period in our mind. We're able to cover our dividend and all these big projects during that period, cumulatively, very happy about that.

And we're able to handle that without a difficulty because we have a lot of projects in the next couple of years that today, as Brian asked the question earlier, there is no exploration CapEx today. So we should be well positioned to handle whatever that will be. I do believe, oil will get into the low 50s personally or to mid-50s after vaccines and COVID and the rebound of demand, but there's a long way to go about that. That's why I believe personally, but that doesn't mean that we're planning to have to have that or anything like that.

Okay. Yes, I'll follow-up on that. And then can you just talk about the Eagle Ford program as well? It's heavily operated in the first half and then you're kind of reliant on nonoperated activity in the back half of this year. Was this to basically help kind of stand the decline from not having any much activity in 2020? And I'm just curious how the volumes are being risked for the back half given the shift from operators in .

Yes. You're right about our operated program. We have 19 wells to come online in the year. 16 in the first quarter, 3 in the second quarter, and then our nonoperated program is second and third quarter weighted. The nonoperated program that we're participating in is quite a large number for us. It works out to be the equivalent, on a working interest basis, of about 10 wells.

So those are material for us relative to our historical non-op contribution. The programs are all well underway, and I don't expect any kind of timing issues or uncertainty around the timing of delivery for the nonoperated because we're working closely with the operators. We know what they're doing. They're executing quite well.

It's these significant non-op positions with BPX. An incredible team. We visited with them in detail last year. They purchased this asset for a lot of money. They're very serious about developing it, and we feel pretty good about that non-op right now, Josh.

What's somewhat unique about the program is quite a few of the nonoperated wells that will come online this year have already been drilled. So they're mostly completion activities in 2021. And production expectation for Eagle Ford is flat at about 30,000 barrels a day.

Thank you. I believe that's our last question at this time. Is there one more?

Okay, everyone, we're going to return back to work here. We appreciate everyone calling in, and that we'll be seeing you in our next quarterly result and appreciate all of your questions and help. And thanks for calling in. Appreciate it. Bye.

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