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

Good morning, everyone, and 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 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 Jenkins.

Good morning, Kelly. Thanks to everyone for calling in today. Before we get started reviewing our 2020 and looking forward segment of our day-to-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, I believe their efforts are misguided. U.S. submission peaked over a decade ago and continues to follow 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. That’s because the deepwater Gulf has the lowest carbon intensity of all E&P business. Last week, the U.S. Department of Interior 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’s potential for delay in the consolidation of approval authority. However, to date, we have been pleased with the progress and are moving forward. Murphy is well-positioned to continue the execution of our short-term and long-term projects including Khaleesi, Mormont, and Samurai, and our non-operated 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 over the past two weeks over 20 approvals given for work in the Gulf of Mexico, not only to us, but to 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 strategy and increased 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 that once the dust settles, 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 both financial and legal reasons. Again, we have a diverse portfolio, and all of 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 on these remarks, and I will return to Slide 2. Murphy has remained steadfast in our strategy despite the turmoil of 2020, maintaining our diverse portfolio while operating in a safe, sustainable, and fiscally 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 a long-term price recovery scenario. We remain focused on our shareholders through our longstanding dividend and our employees, contractors, and communities by establishing and practicing our successful COVID-19 protocols. Our portfolio continues to span onshore and offshore locations in both the U.S. and Canada, which offers many advantages in today’s times. Lastly, Murphy remains a strong company with an exploration program on existing acreage in both the Gulf of Mexico and internationally. Slide 3: Following the OPEC price collapse in the beginning of the COVID-19 global pandemic last year, we focused on a few primary areas to solidify the company’s competitiveness over the long term with multi-basin operations. We completed a significant companywide 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 maintaining 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 a 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 equivalent per day in the fourth quarter. These volumes included impacts totaling nearly 4,000 barrels equivalent from two subsea equipment issues, with production expected to restart in the first quarter of 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 realizations averaging $42, the highest we have seen since the first quarter, 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 per day; it was a dynamic year. My experience includes a record-breaking hurricane season following historically low prices that resulted in industry-wide production shut-ins for a short period. Overall, for the year, we averaged nearly $38 per barrel for realized oil prices and $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, approved reserves remained 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 two primary events. The first was a combination of lower SEC crude oil prices along with Murphy's shift in focus away from oil shale production growth, which resulted in transferring Eagle Ford Shale and Kaybob Duvernay PUDs to probable reserves. The change in capital allocation of the current five-year plan reduced PUDs by over 100 million barrels equivalent. Separately, the sanctioning 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 are lower year-over-year, our North American onshore approved plus probable resource remains near 2.5 billion barrels of oil equivalent. We maintain the ability to rebook our onshore shale PUDs with adjusted capital plans in the future if we decide to do so. The reserve transfers were based on capital timing and not subsurface risk. As in any resource booking, it would also depend on prices, cost structures at the time, and a five-year planning cycle change. Overall, Murphy continues to hold more than 3,400 on-drill 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 reported 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 non-cash 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 of 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 approximately 40% reduction in full-year costs from 2019. Lastly, Murphy continues to protect its future cash flow with the addition of 2021 and 2022 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 12, as a company, we’re responsible to the environment, employees, and our stakeholders; we have a long history of protecting all and part due to our strong internal governance processes. I am particularly proud of how quickly the team established COVID-19 protocols to maintain safe offshore operations with zero downtime or disruptions due to those efforts. Murphy achieved another year of low metrics, including a 46% reduction year-over-year in total recordable incidents. We expanded our internal diversity inclusion practices and programs and maintained a program to aid impacted employees in times of need through our disaster relief foundation, which we’ve used this summer with hurricane relief on the Louisiana coast. Our operations team continues that work on minimizing our environmental impact, such as building a new produced water handling system, recycled water, and 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, of sustainability, following at least our 2020 sustainability report, which features expanded disclosures and metrics, a key highlight is our goal of reducing greenhouse gas emissions intensity by 15% to 20% by 2030 from 2019. The report also outlines diversity and 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 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, in the Eagle Ford Shale business, we produced 31,000 barrels equivalent 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 $15 million for field development as well. We brought online 25 operated wells and 10 non-operated wells earlier in the year. The team continued their efforts on improving well performance and high-grading production-enhancing projects in facility and artificial lift optimization. Murphy is seeing an average decline rate of 24% for all wells drilled prior to 2021, which in our view is very well-positioned. On Slide 16, regarding the Kaybob Duvernay project, the company produced 10,000 barrels equivalent of 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 the Montney project, bringing online 16 operated wells in Kaybob and 10 non-operated wells in Montney. 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 wells in Kaybob Duvernay so far and 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 Tupper Montney, we produced 234 million cubic feet per day in the fourth quarter and averaged 238 million cubic feet per day for the full year 2020. Approximately $14 million CapEx was spent during the year to drill four 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 the 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 due to unplanned downtime from two 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 continue to progress with operated Calliope scheduled for first oil in the second quarter, and non-operated wells in various stages of completions and tie-ins, and we expect all to begin flowing in the first half of the year as planned. In the Gulf of Mexico, Slide 20: On major projects, we remain on schedule with King’s Quay construction at 90% complete, with drilling set to begin in the second quarter for Khaleesi, Mormont, and Samurai development. The non-operated 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 the beginning of work on a producer well. On Slide 22, in exploration, we participated in the latest OCS Gulf of Mexico lease sale during the fourth quarter and were awarded all eight blocks, with five prospects at a net cost of approximately $5.3 million. As a result, our Gulf of Mexico interests today total 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 target 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 and our oil-weighted portfolio, resulting in free cash flow generation after our dividend. Slide 25: North American onshore capital budget is $265 million in 2021, focused on maintaining flat production in Eagle Ford Shale, with $170 million dedicated to bringing on 19 operated wells and 53 non-operated wells, as well as field development, which is 30% of the total spend. Approximately $85 million is earmarked for the 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 non-operated Montney. Of note, our oil-weighted shale assets maintain a long runway of drilling: 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 the opportunity it brings to our portfolio. We’re seeing the lowest basis differentials in five years. Beyond that, we’ve seen continual improvement in Murphy’s well economics and EURs in the area, creating sustainable attractive cash margins. We’re 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 eastward-bound pipelines, as well as construction beginning on the LNG Canada project, with a plan in-service date of 2025. Slide 27: The Tupper Montney asset has been a strong proven resource with rising EURs in recent years and an ever-improving cost structure, while maintaining a very low subsurface risk. They’ve recently put in place additional fixed price forward sales contracts in 2024, thereby protecting future revenue for the project and showing cash flow generation. That said, we generated free cash flow of approximately $50 million in 2020, which is more than sufficient to cover the cash flow requirements in the next two years as the development is initiated. Overall, the current sanction plan involves 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 formed an attractive play opening trend for 10% non-operated working interest with Chevron as operator. The first well planned is a Silverback prospect, and we will also be provided access to 12 blocks through our participation. Slide 29: We continue to progress our various exploration projects and are excited about the optionality that the non-operated position in the Sergipe-Alagoas Basin in Brazil provides our company. Murphy is working with partners to mature our drilling inventory, and our partner plans to drill the first Brazil well in the second half of 2021. In the Salina Basin in Mexico, we continue to advance our position there. We have many leads and prospects here and target drilling the first exploration well in late 2021 or early 2022. Overview of the LRP on Slide 32: A long-term strategy of a dynamic plan to maximize cash flow while managing CapEx after the dividend remains unchanged. This is our commitment to a flatter oil production profile. Our Tupper Montney development leads to an approximately 8% CAGR from 2021 through 2024, while all growth remains at 3%. 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 would allow for 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 the target of drilling three to five wells per year. Slide 33: As we close out 2020 and lean into 2021, Murphy is sticking with our priorities of managing CapEx, supporting a flatter production profile, and combined with protective hedges allowing for maximum free cash flow generation, strong liquidity, and debt reduction in 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 in our new plans, we’re well positioned heading into 2021. I’ll now end my remarks today and be glad to turn over for any questions anyone may have. Thank you.

Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. The first question comes from Neal Dingmann at Truist Securities. Please go ahead.

Good morning, all. Roger, I appreciate your prepared comments on the federal leases and permits. I’m just going to 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 ban or/and once your current assets are worked out?

Well, actually, as I’ve said, there are short-term and long-term things that we work on every day in the business. It’s a business that requires communication with regulators 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 need 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. In fact, we are ahead of target on regulatory there and have more permits than you would normally have for development at this time. The permits are typically given pretty close to the drilling date and historically have been that way in the Gulf. So we’re well-positioned there. As for what we would do with some kind of scenario like that, I appreciate that question, but yesterday’s executive order did not mention anything about current leasing. We’re finding that everything ongoing, like our project, is being treated as an ongoing project. The way it’s being treated and being worked today, there’s regulatory work going on in a normal business basis today in our building. Naturally, if there were to be some extreme moratorium, which didn’t work well for the government at all during the Macondo time, we would have a lot of flexibility. The first step would be, hey, let’s just stop and have a lot more free cash flow and pay down our 2022 notes with this matter, and then continue on. There wouldn’t be a need to rush into duplicating things that we already have, and that’s our first step. It’s quite helpful to us in that regard. If we are able to get these projects back up and running again, naturally we have a big business in the Eagle Ford that can be throttled and changed because oil prices in any moratorium scenario would make that much more attractive. Our Canadian business is doing extremely well, as our Canadian regulations remain very supportive. So we have plenty of options to replace that production if we wish, with capital efficiency, and much higher oil prices will benefit us significantly. But overall, that's a pretty wild scenario and the work that we’re doing today isn’t pointing toward that scenario in my view, Neal.

I agree with you. And then just my follow-up on sticking with the Gulf, I’m looking at Slide 22, it just really reemphasizes just how many opportunities you have there. Just wondering, Roger, what gets 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 about how you think of that. I would like 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, Oso, and Guilder. That’s a new area for us that we’re very excited about. We feel that we have a seismic advantage in that area. We also have a couple of opportunities near Front Runner, which we’re happy about because they’re nearby. We have a very exciting well to drill at Cascade, Chinook in the long run, which segments in most major Wilcox plays have been very successful. It’s a very big commitment for us in the future, as we anticipate it. We’re also very happy to partner with Chevron in our new Silverback area, which is adjacent to some acreage that we feel has the same geological feature. We are very excited about this partnership with Chevron again. 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, knowledge, and long-term experience in the Gulf. I feel really well-positioned because that’s the kind of collaboration we’re focused on to make sure we acquire the right working interests to help us de-risk our blocks if that were to prove successful. So those are the highlights there, Neal.

Very, very important. Thank you so much.

No, thank you.

Thank you. The next question comes from Dun McIntosh at Johnson Rice. Please go ahead.

Good morning, Roger.

Hey, good morning. How are you doing?

Good. I noticed on the Eagle Ford spend for next year, $170 million, but a little less than a third of that is going towards what you call field development. So can you add a little more color on what you’re going to be building out there?

I’ll have Eric share his expertise to talk 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, allocations, 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 and other things involving ESG in this business all the time while improving our flaring and reducing our emissions. We have a new takeaway pipeline in Eagle Ford to further reduce flaring that we’re excited about. So there’s CapEx allocated to those types of improvements, which are both required and needed at this time.

All right. Thank you. And then for a follow-up on the Tupper Montney. I noticed you’ve been sanctioned on that well program, but looking beyond that, and kind of longer-term with the 6% gas CAGR versus 8% versus the oil over the next three to four years. What are you all seeing up there that you think might be sticky or maybe from a demand perspective? An asset basis has gotten tighter than it has been in five years.

If you look at the data, it was very variable on a very poor basis, very poor of which we did some all AECO type business to protect our risk, which worked very well for us at that time. Then the debottlenecking by TCPL laid the groundwork for these capital works and improvements. There was a time where it was difficult to get the gas to a summer storage facility, and now they’re needing more gas in the country and less capital available by Canadian junior players in Calgary, thereby production has greatly dropped. Now, we can get the gas to storage, which eliminates the high summer month type productions and shutdowns. Also, TCPL had downtime through the years, quite frankly, and, because there’s less than 2 BCF of production, there’s less downtime. We have this large position, which brings the best risk possible. We decided this would be a great area for capital allocation and it’s very good from a greenhouse gas perspective. So we’ve succeeded in this sector over time.

All right. Thank you for all that color.

The next question comes from Leo Mariani at KeyBanc. Please go ahead.

Good morning.

Good morning, Leo.

Hey guys. Just want 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 giving a little bit of look back just on third quarter, you guys were certainly planning on kind of ramping up Eagle Ford here in 2021 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 hasn’t done all that much in the last several months and it’s a little bit better. But not as dramatic 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 just looking like to you that the returns at Tupper just seem better now than Eagle Ford, despite higher oil prices?

Well, it’s not at all that way, as far as the bullishness of oil. We still feel oil can go up, especially with all this regulatory activity. But what we’re trying to do, and what we stated, was to plan our business on a flatter oil profile in shale, especially in Eagle Ford. Because we’re well positioned there with our high oil percentage and very known customers in that area of selling oil. We feel that we’ll maintain that flat production and if oil prices go up, we can make more free cash flow. We want to avoid debt and add free cash flow and be successful as that is coming. Our Eagle Ford team has done a great job in maintaining consistent decline rates, which I think is very critical as well. So it’s not that we’re more bullish on gas—it’s about ensuring we get consistent free cash flows.

Okay. That’s a good color. I mean, just on the Gulf of Mexico here, you guys talked about fairly significant downtime in the fourth quarter, and you talked about some downtime moving into the first quarter as well. Could 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 if there’s a bunch of additional downtime in the first quarter, I would have thought you’d be up more.

We were well positioned going into mid-December in the Gulf and very, very well positioned. We had two one-off subsea events happen that required some equipment to be put offshore and repaired. One was in an operating field and one non-operated. That is in the works now to be completed. We have that planned for this quarter to be recovered. We also have some very nice wells being drilled at Lucius operated by Oxy that we purchased through the Petrobras agreement. That will be coming online, and we will be increasing production in the second quarter in the Gulf with all that. That puts us in a good position, Leo, using that down time to solidify our production.

Okay. Thanks guys.

Thank you. Appreciate it.

Your next question comes from Arun Jayaram at JPMorgan. Please go ahead.

Good morning. Roger, I wanted to ask you about the 2021 to 2024 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 the development projects. I wondered if you could help us think about the year-to-year trajectory from 2022 to 2024.

Arun, if I wanted to provide a year-to-year trajectory, I’d put it on the slide. I have it right here. In four years, we’ve seen two major price collapses in our business and recover back. I don’t think it’s a good idea to disclose year-to-year CapEx. There’s no secret that our CapEx this year midpoint of $700 million is what it is. I think we’re very well positioned to do what we’re doing, and it will contribute to oil production through sheer efficiency. Next year will see higher CapEx than this year, and we’ll start to see that drop pretty drastically afterward. I refer to leave it at that for now; a lot can happen to accelerate that or even adjust it, but that’s our plan.

Fair enough. And my second question is regarding the Gulf of Mexico development program. You guys were sticking with the timeline around Khaleesi, Mormont, and Samurai first oil. Based on what we know today, Roger, and stop me if I’m wrong, you’ve received two of the ten permits for the program at Samurai, number three and number four per IHS. Could you walk us through that? 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 during this 60-day timeout from the DOI based on some of your earlier commentary?

Thanks, Arun, for that. It’s nothing – I don’t know where this idea of ten permits is coming from. We have a ten-well commitment on a rig to do any kind of work we want for a specific price in the Gulf of Mexico. This is actually a seven-well phase one development. Phase one, meaning for the next few years, I think there’s another couple of wells beyond 2023 or something like that. We have four existing wells in the ground that have been drilled, so when I talk about this, it’s Khaleesi, Mormont, and Samurai, which we work as one continuous field. You’re correct that we hold two drilling permits today, and you can’t get the completion permit until the wells are drilled. Completion permits often lag drilling permits, as the drilling permit requires a lot more complex documentation. It would not be norm to have all permits approved ahead of schedule. But I believe we’re well ahead to have what we have now because we are starting to work in April. There’s also preparatory work being done for pipelines, and our regulatory engagements are ongoing.

Great. Thanks a lot for that color, Roger.

Thank you. See you soon.

Your next question comes from Brian Singer at Goldman Sachs. Please go ahead.

Thank you. Good morning.

Good morning.

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. Can you add more color on what has changed beyond that? And B, is that 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 handle that for you, Brian, and I’ll come back to address any other question you might have.

Brian, well performance is driven by two things: longer laterals and improved recovery rates per lateral foot or meter. 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, to 12,000-foot laterals. Our plan is to maintain about 3,000-meter laterals for this development program. 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, thank you. 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 baked into either CapEx or production assuming any exploratory discoveries from here? Is there any kind of risk on federal timing and projects? And can you just talk about Vietnam and whether there’s anything from CapEx or production perspective?

There’s absolutely no exploration success included in the plan, as it never has been. That’s why this talk of delayed permitting really doesn’t impact our company. As we mentioned earlier, we have 15 strong prospects in the Gulf on acreage that we hold. Regarding Vietnam, it’s a field development absolutely in place; it's between 80 million and 100 million barrel project. We can develop it as soon as we submit our field development plan. We’re accustomed to working with regulators offshore worldwide and this process is about the same. However, it’s a bit slower, and until we get that approval, we cannot incorporate it into our plan. But today, it’s not in the plan; it’s what we own today. What we’re doing is very clear. We’re knowledgeable about this and do not have a delay currently built into Khaleesi, Mormont, and Samurai or at St. Malo. I feel comfortable with what I know about the projects, and we’re ahead of schedule on Khaleesi and Mormont, which gives us better flexibility. If anything, we are ahead with our permitting too.

Great. Thank you.

Thank you.

Thank you. The next question comes from Gail Nicholson at Stephens. Please go ahead.

Good morning, Roger.

Good morning, Gail.

I was curious about 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 farm-in opportunities have changed over time and what you foresee in the future there?

Well, there aren’t many operators in the Gulf at our size who have the nimbleness we do, and we’ve been in the Gulf for a long time. We’re a top-four operator on gross operating production in the Gulf and well-known for it. All of our executive team primarily come from supermajors before we have relationships with them and have mutual respect. There’s a lot of opportunities to consider. In this discussion about leasing and whether it will be delayed or if there is no future leasing, we have 54 exploration blocks available. Can you imagine how many BP and Chevron have? Moving forward, there’s been utter silence about stopping our current operations. While farm-ins are attractive, I can’t discuss them too openly as my associates operate more discreetly. But I can assure you that we’re well-positioned for major opportunities, such as Silverback and other areas. We’re proud of our track record.

Great. And then just looking at the Montney, you guys have very impressive all-in costs up there about $1.44 per MCFD. I was just curious as you moved into a more steady-state development program. Do you think there’s room for incremental cost improvement over time?

I’ll let Eric respond to that for you, Gail.

We have a significant percentage of our operating costs that are not variable with production rate. As we fill the gas plant, as Roger mentioned, we’ll get up to about 500 million cubic feet at peak in that project. We’ll see the per barrel or per MCF costs go down. So I would model the cost to be nearly flat with maybe a slight increase due to some new wells, but it should be very minor.

Okay, great. Thank you.

The next question comes from Paul Cheng at Scotia Bank. Please go ahead.

Good morning, Paul.

Hey guys, good morning. Roger, I’m just curious that in your budget, I suppose that you have a range of oil prices you feel for here. Can you share with us what that is? And how the program may change based on changes in oil prices, if prices are much higher than that range, are you pretty much fixed to that and say if the higher oil plants will just go into increasing free cash flow?

We don’t usually disclose our pricing range. We hold an outlook for the next four to five years, starting in low-to-mid 40s. We expect a recovery to reach low-to-mid 50s within two to three years. Our plan today is not to increase CapEx due to the higher oil prices; instead, we want that to deliver more cash flow to our balance sheet to be used wisely to reduce debt at the appropriate time. So no new discussions will evolve from higher oil prices.

Perfect. And for Montney, it’s a great economic situation, so while you do have a lot of inventory. Is there any plan or opportunity to expand beyond that?

We have a unique agreement when we sold this business for a midstream provider to build plants at a fixed price, which we considered a great size for negotiating terms. There are substantial opportunities for $250 million increments available to us. Right now, we’re maintaining a $500 million CapEx on our current plan and will reevaluate if we wish to expand, but we will not increase it just for the sake of doing so. My focus remains on maintaining leveraged free cash flow to optimize our outcomes while staying on top of our expenses. The Montney’s infrastructure is in place, and it’s been successful from an uptime standpoint. Therefore, we’re drilling right in the middle of a newly built infrastructure in our position.

Roger, how does that process work? Who makes the decision to expand the plant? Is it the midstream operator, or do you request and sign a contract with them?

We will have to mutually agree on the next steps with them, and I can’t envision why the midstream operator wouldn’t want to continue growth with us. We represent a good capital partner for them in the market.

Two final quick questions: firstly, you already have a pretty sizable hedging program for 2021. Should we assume you are pretty set or that you will look for opportunities to increase that further?

For 2021 and 2022, we have hedges in place, which has been disclosed in our release recently, and we’re reviewing options to that effect. But right now, we’re in a solid position with our cash flow and liquidity without the pressing need for additional hedging.

Okay. Thank you.

Thank you, Paul.

Thank you. Next question comes from Josh Silverstein at Wolfe Research. Please go ahead.

Good morning, Josh. How are you doing? Hey, good morning. Thanks, guys. I’ll just follow up on the hedges there. You mentioned the $47 number this year to cover the CapEx and the dividend. I’m wondering if that excludes the hedges and 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 will go higher next year since it’s a peak spending, but where would that go in the 2023 and 2024 timeframe as the bigger projects fall off?

Our base number includes the hedges in all calculations. As for the future, we have hedges for 2022 as disclosed here today. That’s all we have. We do prefer to hedge some of our production as environmental conditions dictate our position. We historically haven’t hedged to a great extent; however, we plan to be strategic about that decision. The $47 number won’t shift dramatically, I would imagine, but I’d rather not speculate on it extensively

Okay. 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 2024, where would that $47 fall towards?

Well, I wish I knew. I wouldn’t be here talking to you. However, we’ve not seen significant liquidity. We are currently in backwardation which could evolve, but anytime before there has been periods of time where backwardation pushes further to the right. We have estimated our base price to be mid-40s to low-50s across the board over a five-year estimation. We can cover our dividend while carrying our projects during that period. We’re positioning ourselves for better outcomes as Brian asked earlier about moving to the mid-50s post COVID escalation; however, that’s a long way to go yet.

Okay. Yes. I’ll follow up on that. And can you just talk about the Eagle Ford program as well? It seems heavily operated in the first half, and then you’re kind of reliant on non-operated activity in the back half of this year. Was this basically helpful to kind of stem the decline from not having any much activity in 2020? I’m just curious how the volumes are being rested in the back half given the shift from operators to non-operation now.

Yes, you’re correct about our operative program. We have 19 wells to bring online in the year, with 16 in the first quarter, and three in the second quarter. Then our non-operated program is weighted toward the second and third quarters. The non-operated wells we’re participating in are substantial for us and operate relatively well. That’s equivalent to about ten wells of a working interest standard for us, significant relative to previous non-op contributions. The programs are well underway, and I don’t expect any timing uncertainty around their delivery. We’re aware of what the operators are doing, and they’re executing quite well.

Yes. We feel great about our joint venture with BPX. We had several discussions last year, and they purchased this asset at a significant price. They are serious about developing it, and we feel optimistic about that non-operated status.

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

Okay. That’s helpful. Thanks, guys.

Thank you. I believe that’s your 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 we’ll see you at our next quarterly results. Appreciate all 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.