Murphy Oil Corp (MUR) 2021 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation Third Quarter 2021 Earnings Conference call and Webcast. (Operator Instructions) I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead.

Thank you, operator. Good morning, everyone, and thank you for joining us on our third quarter earnings call today. Joining us is Roger Jenkins, President and Chief Executive Officer; along with David Looney, Executive Vice President and Chief Financial Officer; Eric Hambly, Executive Vice President, Operations; and Tom Mireles, Senior Vice President, Technical Services.

Please refer to the information on the slides we placed on the Investor Relations section of our website as you follow along with our webcast today.

Throughout today's call, production numbers, reserves and financial amounts are adjusted to exclude noncontrolling interest in the Gulf of Mexico.

Slide 1. Please keep in mind that some of 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 2020 annual report on Form 10-K on file with the SEC.

Murphy takes no duty to publicly update or revise any forward-looking statements.

I will now turn the call over to Roger Jenkins.

Thank you, Kelly. Good morning, everyone, and thanks for listening in to our call today. Let's look at Slide 2, we'd like to briefly remind our investors of our story as each tenet of this slide remains in effect this quarter and in the future. Our ongoing execution in our 3 producing areas continues to support our offshore long-term projects. Our competitive advantage of executing in offshore is illustrated by our outstanding progress on our Khaleesi/Mormont/Samurai field and the King's Quay project. We've maintained strong cash flow due to capital discipline that covers our planned spending and debt reductions for 2021 and support shareholders through our long-standing dividend.

Lastly, our meaningful level of board and management ownership highlights our personal interest in the company's long-term success.

Moving to Slide 3. Closing out the quarter, we remain focused on progressing our 3 priorities: delever our company, execute and explore. We continued on delevering during the quarter as we redeemed $150 million of our 6.875% notes due in 2024. And earlier this week, you saw that we announced the redemption of additional $150 million of these '24 notes to occur in December. Therefore, we have achieved our goal of reducing long-term debt by $300 million this year.

I'm even more pleased that our total debt reduction of $530 million or 17% for all of '21 as we progress towards our long-term debt reduction goals.

We remain on schedule for our Gulf of Mexico major projects, including transporting the King's Quay floating production system to the Texas Coast ahead of Hurricane Ida with no impact, while maintaining our timing of first oil in the first half of 2022.

Our strong execution and capital discipline has led us to be able to reduce the midpoint of our capital budget by $20 million for 2021, down to $680 million.

Lastly, we are pleased that the partner group has come to an agreement on the Terra Nova asset life extension project and work will begin in the third quarter.

With regard to our exploration program, we completed drilling the nonoperated Silverback exploration well during the quarter. The well has been plugged and abandoned, and Murphy has fully expensed the well. We will continue to evaluate results across our working interest blocks.

Looking forward, we're excited to begin the drilling of the Cutthroat exploration well in Brazil this quarter and advance our 2022 exploration drilling plans with our partners.

On Slide 4. Our third quarter production of 155,000 barrels equivalent per day was comprised of 59% liquids. Hurricane Ida had a significant impact on the industry in the Gulf. We were able to safely redeploy our people offshore 5 days after evacuation where we experienced minimal damage to our facilities. We could have restarted production at that time. However, the issues affecting third-party downstream assets kept our production offline longer with a slow return to full activity. As a result, we had 12,800 barrel equivalents of impact due to Hurricane Ida in the quarter.

Even with the storm impacts, our consistent onshore operations and capital discipline placed our net accrued CapEx at $103 million, which was below guidance.

We also saw stronger realized pricing, averaging just over $68 per barrel in the quarter. Our natural gas averaged $2.77 per 1,000 cubic feet. Natural gas liquids was also very high and averaged $33 per barrel in the quarter.

On Slide 5, Hurricane Ida hit the Gulf Coast this August as a Category 4 hurricane. Its path put it directly over critical third-party offshore pipeline hubs, onshore terminals and natural gas processing plants. This unique track, combined with intensity and physical impacts of the storm this size, created devastation and operational loss not seen since Hurricane Katrina 15 years ago.

As a result of this hurricane, Murphy production for the year was reduced by approximately 4,400 barrel equivalents per day. Fortunately, we have long-standing agreements in place for our temporary shore bases, which enabled us to redeploy personnel quickly and safely only 5 days after the event, much faster than most of our peers. Also, we were one of the first companies able to resume our drilling following the storm at our Khaleesi/Mormont/Samurai project.

On the ground, we followed our disaster response plan and quickly activated our incident team, sourcing supplies and arranging transport to deploy the items to our impacted workers so they could take care of their homes and families.

Overall, I believe we had an exceptional hurricane response that put us in the best position possible to resume operations as soon as third-party downstream capabilities were back online.

I'll now turn the call over to our Chief Financial Officer, Mr. David Looney, to give a financial update of the company.

Thank you, Roger, and good morning, everyone. For the third quarter, we reported net income of $108 million or $0.70 net income per diluted share. Certain after-tax adjustments included a $44 million noncash mark-to-market gain on derivative instruments, a $22 million noncash mark-to-market loss on contingent consideration and a $54 million noncash gain on asset retirement obligations due to the multiyear deferral of expected Terra Nova abandonment expenditures following the project sanctioning. As a result, we reported adjusted net income of $37 million or $0.24 per diluted share.

Cash from operations for the quarter totaled $405 million, including the noncontrolling interest. After accounting for net property additions and dry hole costs of $119 million, we achieved positive adjusted cash flow of $286 million.

Slide 7. Our third quarter CapEx was notably lower than original guidance for 3 primary reasons: number one, we received an $18 million credit for Terra Nova from exiting owners upon close of the agreement; number two, we were also able to reduce cost for various Gulf of Mexico projects by a net of $18 million; and number three, a portion of our spending was shifted from the third quarter to the fourth quarter this year due to timing differences.

Overall, our capital discipline and offshore execution has enabled us to reduce our CapEx midpoint by $20 million down to $680 million with our range tightening to $675 million to $685 million. This is even more significant when noting that this number includes the $20 million acquisition of additional working interest in the Lucius field in the first quarter of 2021.

Slide 8. Turning to the fourth quarter. We're forecasting a production range of 145,500 to 153,500 barrels of oil equivalent per day with a midpoint of oil production at 81,000 barrels of oil per day. This range includes approximately 4,500 barrels of oil equivalent per day of Gulf of Mexico facility downtime for the quarter, which occurred in October, as well as planned non-op downtime of 2,200 barrels of oil equivalent per day later in the quarter.

We are reinstating and revising our full year 2021 production guidance with the previous low end of the range set as our new midpoint after experiencing Hurricane Ida, which averaged out to a 4,400 barrels of oil equivalent per day impact for the full year 2021. We now forecast '21 production of 156,500 to 158,500 barrels of oil equivalent per day. Our full year oil midpoint of 87,000 barrels of oil per day is up 6% from our original guide and is forecast to comprise 55% of total production for the year.

All of this reflects our priority on execution as we have been able to lower CapEx while increasing our oil production and ultimately generate sufficient free cash flow to redeem $300 million of long-term debt, all despite experiencing production impacts from a significant hurricane.

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

Thank you, David. As you look at Slide 10 in our North American onshore business, our onshore drilling and completion activity is nearly complete for 2021. We plan to bring online 4 operated wells in the Eagle Ford Shale in the fourth quarter, and that will wrap up our program for this year.

On Slide 11, in the Eagle Ford, we produced 37,000 barrels equivalents per day in the quarter, comprised of 7% oil and 86% liquids. We plan to bring online, as I just said, 4 wells in Catarina in the fourth quarter, 2 Upper Eagle Ford Shale, 2 Lower Eagle Ford Shale and 1 in the Austin Chalk. Our total CapEx for this year will remain at $170 million in this play. We are pleased that for 2021, we are now achieving approximately 9-month payout wells across our Eagle Ford Shale business.

Slide 12 in Catarina. As mentioned previously, we have 4 Eagle Ford Shale wells coming on here this quarter. All 4 wells are located in our Catarina area and we've seen incredible results this year as part of our operation, including achieving the highest oil cut in Dimmit County and producing 60% above the type curve, resulting in 6-month payouts in Catarina.

Other companies have also reported strong production results in this area, particularly in a new Austin Chalk zone play in this area. With our Austin Chalk test we planned in the fourth quarter, we're hoping to further derisk approximately 110 Austin Chalk locations in Catarina for future development.

Slide 13. In Tupper Montney, we produced 292 million cubic feet per day. Our 2021 wells have achieved record high IP30 rates for the company and also in comparison to industry through modifications in flowback facilities, wellhead equipment and procedures. Overall, we're seeing IP rates more than 50% higher than the previous 3 years and 19% CAGR in IP rates since 2013.

As we look on to Slide 15 in our offshore business, our Gulf of Mexico projects continued to advance and we're now drilling a final well at our Khaleesi/Mormont/Samurai project before advancing to completions later in the fourth quarter. In September, we were able to quickly resume drilling following Hurricane Ida with no impact to our schedule for first oil in the first half of next year.

The nonoperating St. Malo waterflood project continues to progress with installation of a multiphase pump.

We're fortunate these projects avoided the impact from the hurricane, and we're excited as we advance this moving forward.

Slide 16. The King's Quay floating production system successfully transported more than 14,000 miles from South Korea to the Texas Coast during the quarter and arrived just ahead of Hurricane Ida with no impacts. Project work continues and the FPS will soon be moved to its final location in the Gulf, ahead of receiving first oil in the first half of next year.

I'm very pleased that the incredible work everyone has done to keep this project advancing on schedule, especially during COVID, all while remaining in a healthy, safe environment exemplifies our long-term offshore execution ability.

Slide 17, Terra Nova. During the quarter, the partner group came to an agreement on the Terra Nova asset life extension project, which is expected to extend the production life of the FPSO by 10 years. As a result of the agreement, the government of Newfoundland and Labrador will be contributing up to USD 164 million in royalty and financial support with the 3 partners contributing in aggregate matching basis. Murphy's total future net investment of the project will only be $60 million.

Work has begun on the FPSO, which has sailed to Spain to dry dock through most of next year before an anticipated online date in the fourth quarter of 2022.

On Slide 19, involving exploration in the Gulf. We continue to hold a sizable exploration position in Gulf, and we're excited that we will have a lease sale on November 18 and it's moving forward with no changes in royalty rates or other matters.

Last quarter, our operating partner, along with other major energy peers, completed drilling the Silverback exploration well. Well has been plugged and abandoned, and Murphy expensed the well. We'll continue to evaluate results across our working interest blocks.

Slide 20, concerning Brazil. We're excited to work with our operating partner this quarter to spud the Cutthroat exploration well, the Sergipe-Alagoas Basin in Brazil, with an approximate net cost to Murphy of only $15 million. We hope this well is the first of many in the basin. We look forward to the optionality and resource potential the well provides.

As we look at our long-term strategy on Slide 22, our disciplined long-term plans remain intact as we continue on our path to delevering, executing and exploring. As previously disclosed, we're targeting an average CapEx of $600 million from '21 through '24 with production CAGR of only 6% during that period. Our long-term oil weighting remains at approximately 50% through 2024, and this combined with our average 75,000 barrels of equivalent per day produced offshore, will support significant free cash flow generation as it's already done this year.

We plan on maintaining a low production CAGR and capital discipline even in a period of these higher prices we're seeing. This will allow Murphy to pay down debt faster and advance returns to shareholders, and we have no plans to change the strategy at this time.

Our debt will be reduced by half, down to $1.4 billion by the end of 2024, averaging only WTI $55 per barrel pricing.

Further, our strong cash flow will continue to support our cash returns to shareholders.

Our exploration program and portfolio of more than 1 billion barrels equivalent net risked potential continues to be another focal point for our company.

Longer term, we appreciate the optionality afforded us with significant free cash flow generation as well as we have the ability to allocate capital more broadly between funding asset development, exploration success, additional debt repurchases and returning more cash to shareholders.

On our focused priorities on Slide 23, our team has done a tremendous job this year remaining focused on our priorities and we've achieved, I'm sorry, a lot as a result of this discipline.

As announced earlier this year, we'll be redeeming another $150 million of senior notes, thereby achieving our delevering goal of $300 million in long-term debt this year. This is a great first step in our plan of reducing total debt in half by the end of '24. Assuming long-term oil prices of $55 per barrel, at current share prices, we're able to achieve this 1 year earlier.

We continue to execute well on our major Gulf projects as well as reducing onshore drilling and completion costs through ongoing efficiencies. Most importantly, we maintain a safe work environment for our employees, contractors and surrounding communities.

Lastly, our priority of exploring supports Murphy's longevity, so that we may continue to finally produce oil and natural gas to achieve our mission of providing energy that empowers people for the next 100 years. We achieve this by participating in the drilling discovery in Brunei earlier this year. We're excited about the prospect in Brazil that we'll spud later this quarter with our operating partners.

Further, we're advancing and finalizing our '22 exploration plans and partners as everyone completes their budgeting process, and we're looking forward to next year's opportunities.

In closing, I'd like to congratulate all our employees for another quarter of strong execution and capital discipline. I'm thankful that everyone remained safe during Hurricane Ida, incredibly appreciative to those who displays Murphy's values and helped our colleagues and families clean up and begin repairs to their homes following the storm.

With that, I'll turn the call back to the operator for your questions at this time. Thank you.

(Operator Instructions) Your first question comes from Neal Dingmann with Truist.

Roger, I was pretty excited about the upcoming Cutthroat. I'm just wondering besides, could you maybe talk about your thoughts on, I know it can vary, but potential timing around that well? And then any other sort of notable exploration wells you'd consider around the quarter?

Thank you, Neal, for that question about our program. That's one of our key tenets and a differentiator for us. We see that well here pretty soon, Neal. I'd really like to leave the comment at that, but we're hopeful to spud the well this month.

As far as next year's program, we're looking today finalizing our budget. It's typical to be the case at drilling a nice well in Mexico and another well in the Gulf of Mexico, which we would both serve as operator. And those will be nice wells, the Gulf well especially, Mexico being a larger well on the size of mean resources naturally. And happy about those and have a lot of opportunities, both places to drill, and that's in our plans at this time, Neal.

Okay. And then just one follow-up, I'd really like to see that near-term upside at St. Malo on the waterfloods. I'm just wondering would you consider or is there potential for bringing some other waterfloods on in the coming quarters? I don't know what the plans for that is.

No. Today -- thank you, Neal, for that. Historically, waterflood projects have really been an international -- you may not know this, we're one of the leaders in water injection and deepwater in the world. The Gulf of Malaysia was developed totally in that way. It's very uncommon in the Gulf. There are some of these big Wilcox projects that will have this. And it's a different cost structure here and a different reservoir type development in the Gulf. It's not that common. We are evaluating at Dalmatian, which has been, again, tied to more of a reservoir energy perspective to St. Malo and looking at that in our long-term plans.

Your next question comes from Paul Cheng with Scotiabank.

A number of questions. You talked about the balance sheet start to quickly getting back to shape and you're going to accelerate the cash return. Can you talk about between, say, fixed dividend, variable dividend and buyback, how should we look at when you reach the point you will be able to accelerate the return? And what's the precondition for that to happen?

Thank you, Paul. That's a good question for us and a company that does have a long policy. Like many others in 2020, we reduced our long-standing dividend by a good portion, 50% in that case. We still feel that we're a very nice dividend-paying company. We put that with our capital discipline that we've been exhibiting here to allow us to allocate our free cash flow to really reduce our debt, Paul. We want to get our debt in half, as we've said, and I said earlier this morning, we reduced our debt in half by the end of '23 with the strip pricing today.

So we know that we're an established company. We want to have lower debt while returning cash to our shareholders. That's been our policy and practice. That's no surprise. And at these oil prices, as I just said, we'll be able to accomplish those objectives at a faster pace. And if this were to occur, we do have one big advantage in our company with lack of equity issuance at only 154 million, 155 million shares, that an increase that you read about from our peers really isn't a lot of money for us.

So that would be under evaluation in near term and along with our budgeting and pricing. And we'd like to lower the debt first and we're hopeful to get the debt done, but a simple increase in dividend is not an expensive venture for Murphy Oil.

And Roger, can you talk about variable dividend and buyback, which you indeed are going to have excess cash in addition because, as you say, you only have 154 million shares. So raising the fixed dividend, not necessarily that much money more that you really want to raise it that high, I assume. So the excess cash flow in discount pricing. So between the variable dividend and buyback, do you or the Board has a preference one way or the other?

We have been so focused on our delevering, which is the left-hand pillar of our 3 focus areas, Paul, quite honestly. That's our first step. And naturally, as you go into a budget season with oil, around 80 different views can take place.

I don't want to get ahead of my Board on that, but I would say at Murphy we're more attuned to dividend and getting our dividend back. We're a dividend payer for 60 years. And that would be best for us. And of course, a variable dividend, I suppose, can come into that mix. And I would say at this share count, that would be the basis today, Paul.

Okay. And the second question is on hedging. With the balance sheet is getting in better shape, should we -- looking at hedging, you're going to significantly reduce your hedging position going forward or that you continue to be very aggressive on the hedging? I mean, strategically, why do a lot of hedging if you have a strong balance sheet and your reinvestment rate is relatively low, your breakeven requirement is low.

Yes, Paul, I'm going to provide just a high level and let David get into more of that with you. We are not going to be a company that hedges ever more than about 45,000 a day or high for oil. And we have some -- make sure some protections to ensure that we do not ever have to go to the bond market for the '24 notes that we've greatly reduced. And that's our overriding thing at this time. I'll let David provide you more color on that, Paul.

Yes, Paul. Great question, by the way. Thank you for that. The way we think about hedging at this point, as you point out, really is to think about it in the context of our continued debt reduction plan, which, of course, is 50% by 2024. Roger mentioned we really don't ever hedge more than about 50% of our anticipated oil production.

And recently, as you've seen, as we disclosed, we've chosen to utilize collars for the remainder of our '22 program and we've been able to achieve a floor price of about $62, a little bit more than that, at an average ceiling of almost $75. We like this structure because it does provide us some downside protection so that if certain things were to happen in the oil market, we'd still have really good cash flow from those hedges that would allow us to continue our debt reduction plan.

And of course, if the prices stay where they are today, then we're going to be able to reap the benefit of those higher prices, which as Roger mentioned earlier, would also allow us to pay down our debt faster.

So we think about it in that context. And we've never really been a company that other than our gas position in Canada and the Montney, we've never really hedged terribly far out longer than 12 to 18 months. So that's been our consistent approach historically, and I think we're sticking with that now.

Okay. Final question, Roger. There's a lot of assets up there for sale, including, I think, Conoco, after they closed the Shell deal, probably would do quite a lot of Permian asset sales. And Petrobras, your partner in the Gulf of Mexico, is also putting their asset up for sale. Can you talk about, from an M&A standpoint, how the company is looking at that, whether you think that currently it's a buyer market or a seller market from your perspective?

Well, Paul, thank you for that question. We have been very active in M&A, both selling and buying over the last 8 years for sure. I think we've done $8 billion of deals in the company to reposition ourselves to where we are, and it's helping us pay down debt and we have a lot of EBITDA per barrel from that.

We look at a lot of M&A. I would say we focus our M&A efforts in offshore. We have ample locations in onshore and want to make our onshore business, it's running extremely well right now at a very consistent production and want it to be a long-term free cash flow provider like all shale peers today.

Offshore, we see a competitive advantage in certain assets and certain issues. But instead of saying buying or selling market, it has to be a certain rate of return at the way we do M&A and how we analyze PDP and 2P type reserves in a price deck with the information that we have of being long-term offshore players.

And that type of return and will it supply the free cash flow to be accretive to all of our debt reduction metrics and the tight return that we want and risk and the discounting of those cash flows with that risk is how we think about it more than just being a buyer or seller. Because there's not that much competition to buy, Paul, and we're a known operator and can look at a lot of offshore properties and add value and cost structure improvement to most things.

So that's how we're thinking about it today, Paul. Thank you for that question.

(Operator Instructions) Your next question comes from Charles Meade of Johnson Rice.

I had little difficulties on my end, got dropped, but I'm glad I got back in. Roger, I'm wondering if you can share with us -- I imagine you have something like a Gantt chart or some kind of schedule that you're keeping an eye on for -- to track the progress of King's Quay to your start-up. Can you share with us what the key milestones are, what the key lines of activity and heavy lifts are that you are really focused on?

Thanks, Charles, for that. And King's Quay's gone well. There is a Gantt chart, it has 723 lines on it and they usually condense it down for me, Charles, so we may understand it. A lot going on there.

But we're doing very well there. Very, very well. We visited the facility recently. It's the most advanced facility at this stage of the game I've seen in my career. It's in great shape, great condition with the tow over, getting ready to tow it offshore in a week or so.

So to me, the issues are towing it out, which shouldn't be a problem, mooring it up, the mooring or prelay. And we do have a lot of pipelines to lay in the field for each for the wells and manifolds, umbilicals. There's 2 vessels in the field laying pipe today. We'll be towing the vessel out very soon and establishing the mooring. And then we're out in the field drilling. We have interface management to manage that. That's common to our business.

And feel well positioned at King's Quay today. But there's always many items to execute there, but feel real good about King's Quay and the associated jewelry that's on the mud line to produce these. There are 3 fields, Khaleesi, Mormont and Samurai, and feel real good about on the execution of the facility and the pipelines, et cetera.

So if I understood you, Roger, just really getting the facility out there, getting the mooring lines secured, which are, I guess, prepositioned in really just the ongoing lay of the infield flow lines. Is that...

Yes. If I wasn't clear enough, Charles, I apologize. That is the key part. Then of course, the rig has to complete the wells on time, and we want to maximize the flow of how many wells we can have before first oil. So it's a matter of organizing that.

We may flow earlier, but with less wells or flow later with more. And we got to get the rig to complete the wells. Of course, these wells are predrilled with pay at Khaleesi and Mormont. We're still drilling at Samurai. But we're progressing every day on schedule and have been real fortunate on it and real, real pleased about the progress.

And then if I could ask a question about the Petrobras sale of their, I guess, it's the remaining 20% interest in your JV. Can you offer any comments on that process? And then maybe specifically, do you have anything like a pref right for that 20%?

Thank you, Charles, for that. Yes, the Petrobras deal, as you know, has been a very, very nice deal for our company, helped them as well. They wanted to exit and remain partial owners of that. So I think they would be very pleased with our execution and progress so far. They have determined they want to sell their piece. We do have a pref right and we'll be analyzing that.

But just like to the previous question, you might have been off-line, with Paul at Scotia, we have to have certain returns in the certain aspects of deal that we would like as to the risking, but we really understand all the assets because a lot of them are ours and we've run them for a long time. We feel advantaged from that perspective.

But they'll have a process. We're going to probably participate in it and move forward after that and see how that goes, Charles.

Your next question comes from Leo Mariani with KeyBanc.

Wanted to just touch base on the Silverback well here. Just wanted to get a sense from you guys. Did you see any hydrocarbons in that well? And what type of information do you think you may have learned here because I think you have a bunch of other acreage in the area?

Thanks, Leo, for that question on exploration this morning. What I can say about it, yes, we did find some hydrocarbon in the well. And the well is being evaluated and tied into our blocks and to the blocks that we farmed into. But we expensed the well and the well is plugged and abandoned and we have a limiting disclosure among our partner group on it, Leo, quite frankly. And that's kind of where we are today, I'm afraid, just to talk about.

Okay. Understood. And just wanted to touch base. I think, Roger, in your prepared comments, you talked about your longer-term plan, '21 through '24, kind of $600 million of CapEx, 6% type of production CAGR.

Just wanted to get a sense. I think you rolled this plan a while back. I think the plan was for '22 to kind of be the high point for capital just due to a lot of the King's Quay CapEx that needed to kind of roll through here. So just wanted to confirm if that's still generally the thinking from you folks? And just want to see if you had any comments on inflation and how that might impact CapEx over that plan.

Thanks for that question, Leo. Before I answer that, I think the main thing for us is in probably 2 years ago -- no, a year ago, 2020, a year ago, we formulated this plan to keep our onshore businesses [flag], have our Montney long-term projects support our offshore projects, pay down debt and all that. And we've done very, very well at that. And the CapEx to -- and what I'm proud of today is that after another year of all the comings and goings and the business that we work in that we can maintain all the attributes of our long-term strategy slide for now well over a year, which I think is positive, considering what we do in our business.

And the CapEx for next year will be higher, I've spoke to that before. And it will be the higher year because of what you said. And we're moving it along in this plan. I'm very happy for that plan and oil prices are helping us delever faster. And then keeping the plan in shape with these numbers that I mentioned in my comments, which is a reading of the slide, I'm real happy about.

As to inflation, Tom Mireles is here. He runs Technical Services at the company, including supply chain, and I'll let him talk about our views on inflation there, Leo, if you don't mind. Thank you. Here's Tom.

All right. Thanks, Leo. Yes, this is definitely something we keep our eye on and our supply chain group working with the operations group, try to adjust where we can to make sure we can deliver the plan, as Roger described. This year, we definitely saw with the recovery of the global economy that there was in the market some tightening, but it really didn't impact us fortunately. A lot of what we had planned for '21 was already under contract, especially if you consider the Gulf of Mexico projects with long lead items.

And then looking at next year, we're certainly seeing some categories go up, but we're also seeing some come down, in particular, around the OCTG category. That's where we saw some inflation.

But really, for us, earlier this year, we talked about our ability to drill our onshore wells for about $5.5 million a well. And when we look to next year, we think we can deliver the same. And for us, it comes down to changes in how we design and operate our wells. It comes down to lateral length and a mix of the drilling areas that we're going to be focusing on.

And then longer term, in the longer plan that Roger talked about, we do incorporate some modest inflation around 3%. So a lot of what he is referring to, has that baked into the longer-term view.

Okay. That's very helpful. And just last one here for you guys. Just on exploration, I guess you have a well planned in Mexico for next year. I just wanted to kind of get your thoughts on how you rank Mexico from a high-level perspective on exploration, given some of the changes in the political and kind of regulatory regime down there. Just want to get a sense if you look at Mexico maybe as not being as prolific as maybe it could have been a couple of years back as a result of some of those changes.

Thanks, Leo, for that. No, I don't see that changing in any way as a prolific-ness, if you will, if that's the word around Mexico. We have been able to permit and gain approvals of everything we've ever wanted. I think there are some issues there around other matters, unitization and things in which we're not a party. There's been some nice success by European majors around the trend that we're drilling. We're operator there. That's also an advantage. It's well offshore. We feel comfortable about that part of the business and treat it as another nice exploration well to drill, very similar to a project that we would see seismically in our long-term history being in the Gulf of Mexico. I don't see the yakking that we hear around that involving us too much, and we're able to do what we need to do.

There are no further questions from our phone lines. I would now like to turn the call back over to Roger Jenkins for any closing remarks.

Appreciate everyone calling in today, and we'll be talking to you at the end of our next quarter with our budget and things of that nature. And thanks a lot for dialing in. See you next time. Thanks.

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