康菲 (COP) 2022 Q4 法說會逐字稿

Welcome to the Q4 2022 ConocoPhillips Earnings Conference Call. My name is (inaudible), and I will be your operator for today's call.

(Operator Instructions)

I will now turn the call over to Phil Gresh, Vice President, Investor Relations. Sir, you may begin.

Yes. Thank you, operator, and welcome to everyone joining us for our fourth quarter 2022 earnings conference call. On the call today are several members of the ConocoPhillips' leadership team, including Ryan Lance, Chairman and CEO; Bill Bullock, Executive Vice President and Chief Financial Officer; Dominic Macklon, Executive Vice President of Strategy, Sustainability and Technology; Nick Olds, Executive Vice President of Lower 48; Andy O'Brien, Senior Vice President of Global Operations; and Tim Leach, adviser to the CEO.

Ryan and Bill will kick off the call with opening remarks, after which the team will be available for your questions. A few quick reminders: First, along with today's release, we published supplemental financial materials and a presentation which you can find on our Investor Relations website.

Second, during this call, we'll be making forward-looking statements based on current expectations. Actual results may differ due to factors noted in today's release and in our periodic SEC filings.

Finally, to make -- we will make reference to some non-GAAP financial measures. Reconciliations to the nearest corresponding GAAP measure can be found in today's release and on our website.

With that, I will turn the call over to Ryan.

Thanks, Phil, and thank you to everyone for joining our fourth quarter 2022 earnings conference call.

As we sit here today, there are a number of cross-currents in the global economy. While the energy sector is not immune to potential macro headwinds, our fundamental outlook remains constructive. On the demand side, we think that growth will continue in 2023, aided by a normalization in China mobility following the lifting of COVID restrictions. On the supply side, we believe the continued producer discipline and the expected impacts of Russian oil and product sanctions are likely to keep balances tight. So while commodity prices are currently not as high as they averaged in 2022, we see duration to this up cycle.

Now stepping back, we remain steadfast in our view that a successful energy transition must meet society's fundamental need for secure, reliable and affordable energy while also progressing towards a lower carbon future. While we all recognize the challenges that global energy policymakers face to achieve the goals of the Paris Agreement, it is clear that doing so requires an all-the-above approach. This can be done by enacting policies that encourage the development of lower emission energy sources and oil and gas resources.

These policies should include efforts aimed at fiscal stability, streamlining of the permitting process, increased transparency on timelines and supporting critical infrastructure. These are not just necessary for the oil and gas industry, but also for nuclear, hydrogen and renewables, all of which will be necessary to deliver on the energy transition.

At the end of the day, it's critical for our administration to remember that North American energy production is a stabilizing force for both global energy security and meeting energy transition demand. Meeting that demand will require investments in medium and long cycle projects in addition to short-cycle U.S. shale. This is why you see ConocoPhillips leaning a bit further across our deep and diversified portfolio in 2023, whether it's the Lower 48, where we achieved record production in 2022 or our diversified global portfolio, ConocoPhillips is well positioned to meet the world's long-term energy needs while also reducing our own emissions footprint.

Shifting to our 2022 performance. ConocoPhillips showed continuous strong execution across our triple mandate. We generated a trailing 12-month return on capital employed of 27%, the highest since the spin. We delivered on our plan to return $15 billion of capital to our shareholders, which represented 53% of our CFO, well in excess of our greater than 30% annual through-the-cycle commitment, and we further advanced our net zero operational emissions ambition with a new medium-term methane intensity target consistent with our recent commitment to joining OGMP 2.0.

Now looking ahead, ConocoPhillips is well positioned to further deliver on our triple mandate in 2023 with a well-balanced capital allocation strategy. This morning, we announced a plan to return $11 billion of capital to shareholders, which represents about 50% of our forecasted CFO at $80 WTI.

The other half of our cash flow will be dedicated to reinvesting in the business. From a portfolio perspective, our deep and well-diversified asset base is well positioned to generate solid cash flow growth for decades to come. This is further evidenced by our organic reserve replacement ratio of 177% in 2022. We're also enthusiastic about our new LNG opportunities we are participating in, in Qatar and the United States, which are highly complementary to our existing LNG business, and we look forward to providing you a comprehensive update about our long-term strategy and our financial outlook at our upcoming Analyst and Investor Meeting on April 12 at the New York Stock Exchange.

Now let me turn the call over to Bill to cover our fourth quarter performance and 2023 guidance in a bit more detail.

Thanks, Ryan. Starting with fourth quarter results. We generated $2.71 in adjusted earnings per share. Fourth quarter production was 1,758,000 barrels of oil equivalent per day, which included a 27,000 barrel a day negative impact from weather in the Lower 48. Lower 48 production averaged 997,000, including 671,000 from the Permian, 214,000 from the Eagle Ford and 96,000 from the Bakken.

Moving to cash flow. Fourth quarter CFO was $6.5 billion excluding working capital at an average WTI price of $83 per barrel. APLNG distributions were $639 million and fourth quarter capital expenditures were $2.5 billion, including $2.1 billion of base capital and $300 million for acquisitions and North Field East payments.

On capital allocation, we returned $5.1 billion to shareholders through ordinary dividends, VROC payments and share buybacks while also reducing gross debt by $400 million. Full year CFO was $28.5 billion, excluding working capital at an average WTI price of $94 per barrel in 2022. Full year APLNG distributions were $2.2 billion and full year total CapEx was $10.2 billion with base CapEx achieving our guidance of $8.1 billion and $2.1 billion of acquisitions in North Field East payments. Full year return of capital was $15 billion, while $3.4 billion went to debt reduction with cash and short-term investments ending the year at $9.5 billion.

Turning to 2023 guidance. We forecast full year production will be in a range of 1.76 million to 1.8 million barrels of oil equivalent per day, which represents 1% to 4% of organic growth. Our first quarter production guidance range is 1.72 million to 1.76 million, which includes $35,000 of planned maintenance, primarily in Qatar and the Lower 48. Our full year planned maintenance is expected to be similar to 2022.

On capital spending, we expect a range of $10.7 billion to $11.3 billion, which I will discuss in more detail in a moment. We expect operating costs of $8.2 billion, DD&A of $8.1 billion and corporate segment net loss of $900 million.

For 2023 cash flow, we forecast $22 billion in CFO at $80 barrel WTI, 85 Brent and 325 Henry Hub at current strip prices for regional differentials. Included in our cash flow forecast is $1.9 billion in APLNG distributions with $600 million expected in the first quarter.

Now regarding CapEx, we provide a waterfall in our prepared materials bridging 2022 actual spending to 2023 guidance. Starting with base capital spending. We forecast an increase from $8.1 billion in 2022 to a range of $9.1 billion to $9.3 billion in 2023. The remaining $1.6 billion to $2.0 billion is allocated to longer-term projects. Of this amount, $1.5 billion to $1.6 billion is for LNG projects, which includes Port Arthur, North Field East and North Field South. For Port Arthur specifically, after factoring in expected project financing, we forecast that ConocoPhillips net investment will be just under $2 billion over the 5-year investment period.

However, more than half of this capital investment will be in 2023. For Willow, we're guiding to $100 million to $400 million of incremental spending with the high end of this range, assuming that the project is sanctioned this year.

In summary, we're happy with our strong 2022 results, which would not be possible without the hard work and dedication of our talented workforce. And we are well positioned to balance investing in our deep and diversified portfolio this year while also continuing to return capital to our shareholders.

That concludes our prepared remarks. I'll now turn the call back over to Phil.

Great. Thanks, Bill. As a reminder, just before we go to the Q&A, we ask that you please keep it to one question and a follow-up. With that, (inaudible), we're ready to turn it over to you for Q&A.

(Operator Instructions)

Our first question will come from Neil Mehta with Goldman Sachs.

Yes. Our first question is around Willow and recognize there's still some gating factors to getting it towards FID, but it seems to be moving in the right direction. So just talk about how you're thinking about that project, what remains outstanding to get it to FID and then any thoughts on costs as well. The latest number we have is $8 billion all in. Is that still good to go by? Or how should we think about that?

Neil, this is Andy. Yes, there's been a lot of moving parts on Willow since the last earnings call. So let me just step through where we are in the overall approval process and then I can clear where we are with CapEx and scope. So with the approval process, I think most people saw that the final supplemental environmental impact statement was released by the Biden administration earlier this week. Now that should be published in the federal register in the next day or so and then that starts the required 30-day clock before the ROD can be issued. Now given the Biden administration's commitment to the Alaska congressional delegation, we then expect to receive that ROD in the first week of March. Once the ROD has been issued, our focus for 2023 will be to immediately initiate gravel road construction, ramp-up fabrication and supply chain activities. Now we're going to need to take a look at the ROD in some detail, but assuming it's consistent with the BLM's 3-pad preferred alternative, and there are no new unworked restrictions added, we would then proceed to final investment decision.

So switching to CapEx. 2023 is very dependent on the ROD timing. And as Bill mentioned, we've given a range. So with the ROD timing, any resolutions of outstanding issues, what we're guiding is about $100 million to $400 million of incremental spend in 2023. In terms of the total project costs, we have recently gone out to market to update our cost estimates, and we have seen some inflationary pressures.

We've also refined the scope, including an update to accommodate the BLM's 3-pad preferred alternative. So we're in the process of finalizing our cost estimates, but we'd anticipate the AFE to first production to be in the $7 billion to $7.5 billion range. Of the increase versus the update we provided in 2021, it has been about 50-50 between inflation and scope refinement. So that gives you a pretty good update on where we are with Willow. And then at our April Investor Day, we'll be happy go into some more details.

And that 7.5%, Andy, compares to (inaudible), it sounds like, it would be the apples-to-apples. And then...

That's correct. That's an apples-to-apples.

And then the follow-up is just around return of capital. Last year was an outstanding year, 53% back to shareholders of the cash flow. And the guidance this year, $11 billion also implies very strong return of capital number. I know we often anchored to the 30% or greater than 30%. But is the message we should be interpreting that there's a new normal here around return of capital and the bar has been reset higher?

No, we're not trying to message that. What I remind people is the 30% commitment that we have is through the cycle commitment. We've also signaled to -- or we have also told the shareholders that when prices are above our mid-cycle price, you should expect higher distributions for the company, and that's consistent with what we've done over the last number of years. So as we look today, where the strip is trading where the regional differentials are at, we've kind of picked $11 billion at an $80 price deck. So that's how we're going into the year.

It represents about 50% of our cash flow. But again, that 80 is well above our mid-cycle price in our commitments tied to -- through the cycle kind of mid-cycle price call, and it just represents that we are constructive with the environment that we see today, and we expect the prices to be above our mid-cycle price call, which should inform that the distributions would be above that 30% as well.

Our next question will come from Doug Leggate with Bank of America.

So Bill, I think I didn't actually get to write down the numbers quickly enough. Could you just go through again the expected cadence of the 3 LNG projects. Full disclosure, I think we had expected a slower pace on Sempra or in Port Arthur, I guess. So can you just walk us through what you -- how you expect that cadence to look please? That would be really helpful. I've got a follow-up, please.

Yes. Sure, Doug. I'm happy to. So let me just kind of start with a bit of a high-level view. We've put a bridge from 2022 to '23 in our documents for today. And I'll just -- I'll start with kind of our exit rate. So if you look at our fourth quarter base capital spend, that would annualize out to about $8.9 billion with a low single-digit inflation rate versus '22 exit rate. And we've got some phasing in Norway and the additional incremental emissions reduction that gets you to about 9.2, which is midpoint of our guidance. And then really, the incremental spend is on LNG projects in Willow and that gets us to $11 billion midpoint of the guidance range.

And I think that the primary issue here on cadence is likely the front-end nature of Port Arthur LNG spend, which really the market had no way of knowing. So as you'll recall, Sempra has communicated a Phase 1 gross cost of $10.5 billion for the EPC, on top of which there's going to be owners' costs and other miscellaneous costs to bring the project online.

And Doug, the project currently lining up debt financing for a portion of the spend, so you roll that all together, we would expect our 30% share of the net equity capital to be just under $2 billion over the 5-year investment period. But the front-end nature of equity component is going to result in over half of that $2 billion occurring in 2023. That's what we've included in our 2023 capital guidance.

Now the project is still waiting on FID, but we do expect that in the first quarter, and we will be talking to you more about this in April. But if you've been modeling a more ratable spend over 5 years for Port Arthur, that would be about $400 million in 2023 or about to $600 million to $700 million less than our guidance. So I think that, that might be some of what you're seeing in kind of the LNG spend, and I think it's obvious with over half of the Port Arthur spend in 2023, obviously, the spending in 2024 and beyond is going to be less than a ratable rate. But I think that's probably the main gap in LNG spending that you're seeing.

That's really helpful, Bill. And you're exactly right. We were not expecting half. But of course, that means that the other half is probably more ratable, I'm guessing, over time, but that's really helpful. My follow-up is a favorite topic of mine, Bill. I hate to get in the weeds here, but again, another sizable deferred tax credit this quarter, although it does kind of look a little bit more like your -- almost like you're moving to a new normal based on your U.S. spending, thinking IDCs and things of that nature. Can you move just -- am I thinking about that right? Should we be expecting a ratable deferred tax credit going forward in your cash flow? And I'll leave it there.

Well, yes. So deferred taxes were a source of $0.5 billion in the fourth quarter, Doug, and we had a source of about $700 million in the third quarter. Now the source of those deferred taxes is primarily due to the impact of intangible drilling costs and generating deferred tax liabilities now that we're in a U.S. cash tax paying position. Now as we look at 2023 at current investment levels, we'd expect deferred taxes are going to continue to generate a source of cash on a normalized basis. But I'd expect the deferred tax source full year to be lower in 2022.

Now we are in a U.S. cash tax paying position for the full year, but we also utilized all significant U.S. net operating losses, NOLs and EOR credit carryforwards in 2022. And that utilization generated a larger source of cash last year compared to what we're going to be seeing in 2023.

Our next question comes from Steve Richardson with Evercore.

Ryan, there's been a lot of focus on the Permian Basin of late, certainly from an industry perspective, and not all of it has been good, we'd say. And I'd love if you just took a moment and help us differentiate Conoco's assets in the basin, what you're seeing from your asset. And certainly, some of the performance speaks for itself, but I'd love if you could address that today.

Yes. Thanks, Steve. Let me make a couple of comments, and then I'll turn it over to Nick for maybe a couple of his thoughts in a bit more detail. We're not worried about our long-term development plans in the Lower 48. We see durability to our plans. And I know there's been a bit of noise about productivity and length and durability. And we've been there for a long time. We know what we're doing after the acquisitions that we made over the last 1.5 years. And I don't have any concerns about the durability to length, the efficiency of our program. And maybe I'll let Nick provide a few more detail and color on that comment.

Yes, so I'll give a little more color on that one. Let me start with just the well performance that we're seeing versus the tight curves. So if you look at our 2022 development wells, they've been performing slightly above the curve expectations across all 4 basins, including the Permian Basin. And that strong performance reinforces and validates the development plans that Ryan just mentioned, which is our focus on maximizing returns and recovery while minimizing the future interference. So if we step back in time, we've been incorporating a lot of the learning curve from our developments over the past 3 to 4 years.

In fact, when you look at our accelerated learning curve, we've drilled the most horizontal wells in the Delaware and Midland Basin, more than any other company. So when you combine that data along with our significant operated by others portfolio and then the learnings in our mature development in the Eagle Ford and the Bakken, that's really helped us hone in on the best development approach of the stack.

So in summary, Steve, if you look at our production performance at or slightly exceeding type curve expectations, combined with the development strategy, we're very confident in our long-term outlook for these assets and we'll update you more at AM.

That's great. I really appreciate it. I mean if I could -- just one quick follow-up, Nick. Could you just address the 25,000 acres of swaps and coring up that you mentioned this morning, I would, I mean one of the questions, I guess, is...

No, we didn't catch your question. Thanks.

Sorry, it must be the phone line. The question is on the -- you have the 25,000 acres on the core up. And I'm just wondering if you could address, Nick, how much more to go is there on that side? And where are you just looking at the checkerboard of the map down there?

Yes, Steve. Maybe I'll just go back for the whole audience on what we've done in that space. We've been very focused on the acreage optimization, as you mentioned on trades and swaps. Last year, we completed 15 trades, and that gives us a total about 25,000 acres since the Concho transaction. Now a couple of points I just want to address. These core ups have doubled the average laterally of more than a year's worth of inventory, that's at our current level of drilling activity. Now the ability to drill extended laterals greater than 1 mile can reduce our cost of supply by 30% to 40%. So that's significant.

Now to put that in perspective, Steve, our quality position in the Permian has an inventory with roughly 60% of our wells that are greater than 2-mile laterals, 60%. And then if you look at 1.5 miles or greater, that's an additional 20%. So that's a robust inventory that we have out there.

Now if you will continue to, as you mentioned, the core up in 2023 through acreage and swaps there, but we've got a significant deep robust inventory with those longer laterals.

Our next question comes from John Royall with JPMorgan.

So my first question is just kind of a broad one on the upcoming Investor Day. You guys haven't done one for several years. Anything on what we can expect from the presentation in terms of the longer-term plan? Or maybe a breakdown of certain assets or projects. So just any color on that would be great.

Yes, John, thanks. So we -- I think we'll show how we're pretty excited about where the company has gone. We've got a better plan. It's the strategic and the financial plan of the company and got better duration, better depth, and we'll show that to you what it means for the company for decades to come. I mean -- so we're pretty excited about where it's at. We'll do a deeper dive into where we're at in the Lower 48, our global portfolio as well as the LNG business that we've been developing here over the last 1.5 years. So look forward to sharing kind of our excitement around our plans, where it's headed and just the quality of what we're doing both strategically and financially.

Great. And then just a question on the guidance for 1Q production, a little bit below the full year guide and you guys called out the maintenance number there. But maybe just some color on would be helpful on how you expect production to phase in throughout the year? Should we expect it to be more back-end loaded or maybe more towards the middle, given the later 1Q?

John, it's Dominic here. So yes, I think as Bill remarked, we do have above-normal seasonal maintenance in the first quarter. That's at Qatar Train 6 and 7, but also Eagle Ford (inaudible) our stabilizer facility down there. We've actually been preparing that for a bit of expansion. So that explains the Q1 sort of rate. But thereafter, our expectation is that each quarter will be around 2% to 3% year-on-year growth. So that's really our base case.

Our next question comes from Jeanine Wai with Barclays.

First one, maybe following up on Neil's question on the cash return for the year, we realize that it's still early in the year, but you've already declared the ROC for the first part of the year. How are you ultimately thinking about the split of the $11 billion of total cash return between cash and buyback, and is the buyback more of a function of your mid-cycle price assumptions?

Yes. I think the majority of our buyback is tied back to ratably buying our shares in our mid-cycle price assumptions. So we try to ratably buy some shares as we go through the year. And then we buy some variable shares depending on where we see the market. I would say, as we're going into 2023, right now, we're thinking roughly 50%, 50% between cash and shares in terms of the absolute return back to the shareholders. So the $11 billion would be split roughly 5.5 and 5.5. That's our thinking as we start the year, but we'll watch the commodity price and where things develop as we go through the course of the year.

Okay. Very helpful. I'll pencil that in. Our second question, sticking with '23, but moving to CapEx here. We noticed that there's about $500 million to $600 million of incremental inflation included in the budget versus 2022. And there's some noise with the categorization of the Port Arthur spend. But it looks like Lower 48 will comprise about 60% of total CapEx for '23. And so our question is, how much of that $500 million to $600 million of incremental inflation is in the Permian and Lower 48 versus maybe other parts of your portfolio? And what's your estimate on how inflation ended up by region in '22? And maybe any assumptions that you have in your budget for '23 inflation?

Yes. Let me take a quick high-level shot. I think if you're kind of looking at exit rates from 2022 going into 2023, it's kind of low-single digits. If you're kind of looking at what's the increase annually year-over-year, it's more like mid-single digits. I think the difference we're seeing this year maybe relative to last year is we see that mid-single-digit inflation applying across the whole global portfolio and it's slightly higher in the Permian to the question that you asked.

So yes, we're in -- we're seeing some categories of spend that are key to the company actually start to plateau and maybe even roll over a little bit, one that -- one we're watching pretty closely is OCTG, the tubulars, some of the raw materials that are going into making those are starting to come down and be slight a little bit. So we're starting to see that category spend sort of roll over. We're seeing the rate of increase kind of in the onshore rig market start to lessen a little bit, which is good. We need that -- and so when we kind of wrap all those categories to spend together for the company, it kind of manifests itself in an annual year-over-year inflation in the mid-single digits.

Our next question comes from Ryan Todd with Piper Sandler.

Maybe a follow-up on the Permian. I'm not sure if you mentioned this earlier, but can you talk a little bit about what is assumed in your current guidance, I guess, both capital and production for the year. It sounds like the guide assumes kind of flat activity levels in the Permian versus late 2022. Is that correct? And in terms of how should we think about activity levels? And how should we think about the trajectory of production in the Permian over the course of 2023?

Yes, Ryan, this is Nick. Yes, let me talk -- walk you through that. So as you mentioned, we've assumed a level-loaded steady-state program for 2023 based on that second half of 2022 for rigs and frac crews. The focus for this year will really be around improving capital and operating efficiency. Now we do expect some modest growth in partner activity as the year progresses. And then we have some larger operated pads that will come online in kind of 2Q, 3Q.

So our Lower 48 plan will deliver production in that mid-single digits, with the majority of that growth weighted to the Permian. Now with respect to the profile shape, it will be kind of mid- to back-end weighted in 2023. And as we talked about, Dominic mentioned this, we do have that Eagle Ford, Sugarloaf stabilizer maintenance that's going on. And actually, I'm pleased to mention that the turnaround that Dominic referred to is 5 days, and we completed that successfully in January. Now we will have a little bit of brownfield modifications on that stabilizer through mid-February as well. And then I'll mention 2 kind of month-to-month, we'll have wells, a little bit of lumpiness. But in the back end, we'll be weighted in 2023 for a production profile.

Great. That's very helpful. And then -- as we think about your emerging kind of global gas strategy, how should we think about your approach to the gas portfolio on these projects? Should we expect the majority sold under long-term contracts with a percentage held for spot cells when you look to correspondingly build out your global gas trading capability similar to our European peers? And maybe as you're out marketing these volumes, are you seeing anything to comment on in terms of the environment, whether global gas tightness is helping the sales pricing out there? So any high-level views on your global gas strategy there would be great.

Yes, sure. This is Bill. So I'll just start with -- we've got a really strong understanding and presence in the LNG market and have had for several years. We're regularly selling spot volumes into Asia of our APLNG venture. And we do think that Europe is going to be a long-term market for U.S. Gulf Coast and you will have seen where we recently secured regas capacity in Germany, which we're really happy about and excited about.

And so we're looking at the best options in terms of long-term placements, but these are 20-year projects off the Gulf Coast. And so we think that the long-term strength of international pricing relative to U.S. gas is going to be pretty interesting. And that driver and that strength in LNG, we think, it's going to be driven by its role in energy transition and reducing carbon emissions. So as you see us build out our LNG portfolio over the next few years, we may take some longer-term contract decisions in there. But right now, we're not really disclosing where we're at for competitive reasons in terms of how we're developing that market.

Our next question comes from Devin McDermott with Morgan Stanley.

So I wanted to first follow up on some of the CapEx questions earlier. You laid out the $1.6 billion to $2 billion of spending this year on major projects, and you talked with some good detail about Port Arthur. It's not necessarily ratable across the projects. But when you put it all together, I was wondering if you could talk about how you see the magnitude of major projects been evolving or changing over the next few years outside of Port Arthur and some of the key moving pieces that we should be thinking about across the projects that could move that number higher or lower?

Yes. I think we tried to explain kind of a bit about the front-end loading of the Port Arthur project. So you ought to expect that's going to come down as you look into the 2, 3, 4 years. Some of the other moving pieces, we -- if the commodity price environment supports it, we want to see some ramp in our Lower 48 activities up to our optimized plateau across the various assets. You'll see Willow ramping up if we get an adequate project approval from the federal government. So that will come in. And then obviously, there's some inflationary forces as well as we think about where it's going. So there's a lot of moving pieces, but that's kind of how you should think of the different pieces that we're looking at as we kind of think about the longer-term nature of the capital, and we'll be prepared to talk about that at our analyst meeting coming up in April.

Got it. Makes sense. Just a quick follow-up on NFE and NFS, are those fairly ratable over the next few years? Any additional color on those projects specifically?

Yes. So this is Bill. You saw us in the fourth quarter and make our initial catch-up payment on NFE. And then you should expect that those projects are funding through the next couple of years.

Our next question comes from Paul Cheng with Scotia General.

Can I go back into Permian? You guys talking about earlier in your prepared remarks on the inventory for the 2-mile well. I think the industry also think that the 3-mile may actually was even better. Can you talk about that? I mean, based on where you are today, what's the inventory then on the 3 miles? And whether there's a lot of opportunity there. You also don't know whether there's an update you can provide on the (inaudible) longer-term petrol rate that you expect for Permian and that when that you will be able to get there. So that's the first question.

The second question that I have to say, I was super impressed that your Bakken production is actually flat sequentially from the third quarter given that the winter storm hit and so severely, I mean, how the 27,000 barrels per day, I mean, how much is on the Bakken and how you'd be able to get it so that you can actually get it flat?

All right. Yes. This is Nick. I'll just kind of walk you back through kind of the inventory related to our longer laterals as we've done the core up. Again, over 60% is greater than 2-mile laterals, and that does include the 3 miles as well. So that's a significant part of our inventory in the Permian Basin. We've actually, this last year, in 2022, brought on, I think, more than 30 wells that are in the 3-mile category and are seeing very encouraging results. So we'll continue to execute those as we go forward. As we continue to core up and do swaps, that will give us more inventory as well for that longer lateral execution. Again, you will see probably cost of supply of about 30% to 40% reduction as we drill those longer laterals.

I'm sorry, Dominic, for the 60% you're talking about, how much of -- what percent of them is actually in the 3 miles category?

Yes, Paul, I don't have that in front of me at this point in time, but let's wait until AM and I'll give you a further update on that overall 3-mile categorization.

On your second part of that first question related to plateau. Again, we'll update the group on overall Permian plateau, Eagle Ford and Bakken at the April 12 Investor Day. Obviously, there's a number of factors that go into that. The macro, maintaining execution, efficiency, continuing to capture the learning curve and capital efficiency. Right now, with our middle -- mid-single-digit growth, we feel that's right in line with what we've communicated earlier.

And then your second question was related to weather. Glad you brought that one up. Again, Bill, you had mentioned 27,000 barrels a day for fourth quarter 2022. Just a quick breakdown on that. That's 13,000 for Permian, 10,000 for Bakken and then last 4,000 in Eagle Ford. I think you asked kind of maybe quarter-to-quarter, Q3 to Q4, you're right, it was flat. We're at 96,000 barrels equivalent per day. And Paul, the main driver for that is what we had some really strong operated wells that carried into Q4. And then on the operated by others, we had some larger pad projects come online in Q4 that offset that weather.

Our next question comes from Bob Brackett with Bernstein.

A bit of an old-school question on your reserve replacement. Historically, LNG FIDs were big blocky chunks of gas reserves going into the portfolio. That's not really going to be the case for a midstream asset like Port Arthur. But I'm curious, can you go into a little more detail on the oil gas mix shift on the reserve replacement? And how to think about the cadence of LNG coming in through that?

Bob, it's Dominic here. Yes. So let me talk a bit about that. I mean, we're obviously very pleased with our organic reserve replacement ratio this year, 177%. The real drivers for that, I mean, obviously, the LNG, we did have some bookings there for NFE as we commenced payments on NFE. We also saw some bookings (inaudible) LNG performance and for some project advancements in Norway. Our international portfolio is contributing. But the main area this year was actually in the Lower 48 development program. And that's particularly in the Permian and that included an increase to our PUD bookings by extending the approved area established by reliable technology, which is an SEC term. So it's consistent with SEC requirements. And so basically, we have a very extensive geoscience and reservoir engineering data set across the Permian now that allows us to support that. So -- and you'll be aware, Bob, just the rigor and the process and the controls governing the reserves booking process. So this further demonstrates the depth and quality of our Lower 48 inventory. So that's really the story this year. Going forward, we'll continue to see bookings in the Lower 48, we'll see bookings in Alaska, obviously, with pending FIDs. And then we'll continue to see some LNG bookings as well, particularly on the resource projects as we call them, NFE and NFS, you're absolutely right what you're saying about Port Arthur. So I think you'll see a mix going forward, right, as it stands now, our Lower 48 represents about 46% of our reserves and the remainder across international, but yes, we are certainly appreciating the performance of our sort of diversified portfolio around our reserve booking. So thanks for the question.

Very clear. A quick follow-up on the portfolio. Great opportunities in 2020 to rebuild the portfolio, '21 again in the Permian, '22 was very much an LNG theme year. Is the star of the show for '23 Willow FID? Or how do you think about the portfolio where it stands today?

We're pretty pleased where the portfolio is at. I mean, Dominic did a good job of kind of going across the globe. I think we spent a lot of time over the last 5 years really coring up the portfolio, really focused on getting it as low cost of supply as we can, getting the margins as expanded as we can, leading to kind of the returns and the productivity that we're seeing today. So we're just hyper focused on making sure the efficiencies are there and the returns are there and pretty happy with where we stand today. And then as you rightly note, Bob, we're leaning in a bit on some of these mid- and longer-cycle projects because we're just very constructive. The world is going to need this all. It's going to need low greenhouse gas and emissions intensity oil. It's going to need low-cost supply oil. That's what we're all about. That's what we're doing in our portfolio. And most recently, leaning in on the LNG side because we think the world is going to need this gas as part of the transition that we're going through.

Our next question comes from Neal Dingmann with Truist.

My question is around just production and maybe around the Permian. I'm just trying to get a sense of -- you've got, I think, the 4% -- 1% to 4% type overall growth. So I'm just trying to get a sense of expectations for the Permian, if you would back out obviously, what's going on up in Alaska. Have you all clarified or kind of said what the expectation is at and it sounds like a second part of that, it sounds like it's going to be pretty -- that growth you expect in the Permian, I assume that would be pretty linear for the entire year, if you could comment on those 2 things.

Yes, Neal, this is Nick. Again, for the Lower 48, we'll deliver production growth in that mid-single digits. And again, the majority of that growth is going to be weighted to the Permian. With respect to the profile shape, it's going to be more of mid- to back-end weighted. So we've got some operated larger pads that are going to be coming on kind of the midyear to third quarter. And then we've got a modest operated by other growth going through the year with more on the kind of the back end for Lower 48. Does that help?

That's very clear. And then just one last one. You all are obviously in a fantastic position financially. You've done some really positive M&A deals in the past. I think actually in the last couple of years among the best that I've seen out there. My question that comes in, how do you view the landscape today? I mean obviously, prices are up, maybe commodity prices are up, so maybe expectations are higher, but just wondering, overall, how do you view the M&A landscape?

Yes. Thanks, Neal. I mean we're in the market every day. We're trading. We're thinking about the market, we see what's going on every day. We think generally, there's more consolidation that's needed in our business. It's pretty tough at these kinds of elevated prices, but we watch it every day. I think it -- we've been pretty clear and consistent about our financial framework and how we think about M&A. That has not changed. So as we think about cost of supply, we think about assets that we can make better or can make our company better or improve our long-term plan. We know the assets that we like. And so we watch those constantly. But it's a tougher market at these kinds of prices to transact. And some of the transactions that have occurred this year, we've looked at them, we've seen them. We've watched them. They just don't feel our framework. So they don't make us a better company.

Our next question comes from Paul Sankey with Sankey Research.

Thanks, as always, for the great disclosure. In fact, you guys have been leaders in the industry in many ways, starting with really the first capital discipline, cash return framework. You're in position to make acquisitions at the bottom of the cycle. And now you're saying that you're leaning in is the (inaudible) sort of mega project development using an $85 oil price assumption. Is this an indication that the industry is going to have to follow you? Or is it more that these major opportunities have come up in 2023? And further to the $85 price assumption, could you just remind me what gas price assumption you're using? And what would you cut if oil prices went to, say, $60 over the course of the year?

Yes. Thanks, Paul. No, I think we're -- Yes, I think the -- our view is pretty constructive over the next number of years and through the decade. So the time you want to do some of these big projects sort of front end of the cycle, we probably are a bit unique given our global diversified portfolio. We have opportunities in Alaska and Norway, in the Far East, in the Middle East. So we look at those, make sure they fit our framework around cost of supply and what we want to go invest in. And as we look forward, we believe now is the time to be doing these projects, which is why you see us leaning in on the LNG side. We're constructive on the gas and why we're moving forward with our little project up in Alaska. And (inaudible) this is what the administration has asked us for, U.S. production, this low GHG emission production. This is exactly what the administration has asked us to do as an industry, and that's what we're trying to do as a company.

Now looking forward, I think we'll talk at aim about where we think mid-cycle price is and frankly, we think it's probably come up from where we've been over the last 5, 6 years. We'll show that to you at AM. And then finally, to your last question, yes, we've set a cash return target at $80 WTI, $85 Brent. And I think it's 325 Henry Hub. Those are the assumptions we made that underpin the $11 billion. The price would have to go down considerably. I mean, you said into the 60s, full year average, I think before we would talk about changing that. And we're prepared to use our cash on the balance sheet to fund these projects. That's why we have that cash. That's why we have that financial strength and that resilience. So we're happy to use the cash if we need to. So I think it's resilient across a broad range of prices in terms of what we've established as our distribution target for the year.

And then following on the leadership, you were instrumental in the export ban being lifted. Can you talk a little bit more about Willow? There's obviously some -- you mentioned low GHG. Can you talk a bit about how it fits alongside what you just said about the administration asking for this in terms of its environmental footprint?

Yes, it will be some of the lowest GHG emission production in the world, less than 10 kilograms per barrel. So it's going to be something that we believe is what the world needs right now as we go through this energy transition. We need more oil and gas. We need more base load to supply the world reliable and affordable energy and coming from the United States and North America broadly, in general, is the right thing to be doing right now. And it comes from companies like ours that have over 40-year experience on the North Slope. We know how to do this. We know how to do it responsibly and all the stakeholders support it, including the native community on the North Slope, the congressional delegation, the union labor leaders who need this opportunity for employment in Alaska. So there's full alignment behind what we're trying to go do there. It's just the politics in D.C.

Our last question comes from Bill Janela with Credit Suisse.

I wanted to ask on the pace of CapEx as you move through this year. I'm wondering with all of the major project components that there are some quarters that might be chunkier than others? Or if there are any other timing or seasonal factors to consider? So any guidance you can give there in terms of how to think about the progression of quarterly spending for some of those bigger ticket items as well as the base business would be very helpful.

Thanks, Bill. It's Dominic here. Yes, the way it's going to work out, we think, is pretty ratable through the year. we've got consistent activity in the Lower 48 level loaded. You're right that there is going to be a bit of lumpiness around some of the project spend. So for example, in the first quarter, we do have a modest upfront payment in Q1 on Port Arthur, assuming that's sanctioned. But if you are running a fairly ratable profile, that would be a good estimate.

Okay. Great. Thank you. Operator, I think just wrap up the call.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.