On the second component that we’re focusing in, on reservoir optimization, I’ll draw you to — your attention to Eagle Ford. We’re using kind of techniques where we refrack these wells, kind of late life in the wells. And we’re seeing improved well performance on expected ultimate recovery by 60%, which is very competitive in our cost supply framework. And then I’ll take you up to the Bakken. We’re using infill wells and upcoming edge wells to further increase overall recovery, and these are also a competitive cost of supply. Again, that’s increasing the recovery per pad. And then the final bucket, that enhanced oil recovery component, where we’ve done many pilot studies, mainly in the Eagle Ford, around gas injection, huff-and-puff. And we’ve seen technical success.
We’ve seen injectivity and the corresponding oil response. But I’ll leave you with this on the enhanced oil recovery, these projects don’t compete within our expansive drill 1 inventory at this point in time. We’ll continue to study it and analyze it, and that’s something we can address in the future. So from long laterals to improve completion design to infill wells, we’re improving recovery in our assets.
Operator: Our next question comes from the line of Roger Read with Wells Fargo.
Roger Read: A lot of this has been hit. But I guess I’ll just ask about Alaska. There has been a little more noise up there on the — I don’t know if you call it, regulatory, legislative side, and then we’re about to head into the winter season. So I’m just curious, Willow and other things, what’s going on there.
Andrew O’Brien: Roger, this is Andy. So yes, let me take that one. I’ll start with the legal and then we’ll give you a bit of an update on where we are with the project. So on the legal side, I talked about this on previous calls, there are lawsuits challenging the federal government’s approval of the project. As I mentioned on the last call, we expect to see a ruling on this in November. The preliminary rulings in April were favorable and then the upcoming ruling will address the full scope of the legal challenge. Again, I’m repeating myself a little here, but as I said on the last call, we’re very happy with how the BLM and competing agencies conducted the process, and satisfied all the requirements to grant their approval.
So we’re confident, and we’re looking forward to those court rulings in November as we get ready for the 24 season. And then I think the other part of the legal question you were alluding to is the, separately, in September, the Department of Interior proposed additional regulations for the management and protection of the NPRA. And we don’t expect these draft rules to impact Willow or prevent our exploration program. It doesn’t have any impact on the 10-year plan we’ve previously laid out at AIM. But that said, we are concerned if the rules are adopted as currently drafted, they could impact future developments beyond Willow, in the National Petroleum Reserve Alaska. So the way to be providing feedback to the Department of Interior to try and make the proposed rules more consistent with the existing statute.
And again, I’ll just finish the legal bit with — as a reminder, the statute recognizes the primary purpose of the NPRA is to increase domestic oil supply. So that’s kind of where we are on the legal side. And then just very quickly where we are in terms of the project. Taking a step back here, as I described back at our investor update, Willow, is the kind of project that’s right in our wheelhouse. We’ve got no first-of-the-kind type risk here. It’s 3 drill sites to 1 new processing facility. And our track record and our [indiscernible] of excellence in delivering on schedule and on budget. But specifically to where we are right now, work is progressing well, and our 2023 capital is fully factored into the total company guidance we gave today.
We started the first phase of module fabrication on the Gulf Coast. And then on the North Slope, we’ve successfully opened the gravel mine, and we’re preparing for the 24th construction season. We’ve already got over half of the project scope under firm contract. And these contracts include clauses if we don’t FID the project that we can exit. Now all the contracts we’ve issued today, 75% from a lump sum or unit rate for these type of contracts, we have a greater price and now have limited exposure to future inflation. So as we continue the contract negotiations, our estimate of capital to first production remains unchanged at $7 billion to $7.5 billion that we previously provided. So I think that probably gives you a good update on where we are on the legal and on the project side of things.
Operator: Our next question comes from the line of Ryan Todd with Piper Sandler.
Ryan Todd: Maybe one for you, Ryan, you’ve been on you’ve been busy on the portfolio over the last few years across a wide range of regions and types of assets across the portfolio. As you — and some of that is obviously opportunistic just when the timing of things like Surmont and APLNG came up. But if you take a step back now and look, is there still more to do on the portfolio, in terms of portfolio management? Are there increased high-grading opportunities on the divestiture side that we should expect, as you continue to develop things, or any places that you would like to change or increase your exposure, maybe as you look going forward down the line in terms of long-term competitiveness.
Ryan Lance: Yes, Ryan. No, I think as we tried to show you at the Analyst Meeting earlier this year, we’re pretty pleased with all the efforts we’ve made in the company over the last 4 to 5 years to really, what we think has put out an extremely compelling 10-year plan. So I wouldn’t describe the — really, really like where the portfolio has gotten to. It’s got a — it’s global, it’s diverse. It’s got a great mix, a short-, medium- and longer-cycle opportunities organically to invest in. All those investments lead to 20 billion barrels, less than $40 cost of supply. So we’ve got a lot of visibility into what we think is a great plan. We’re ruthless high graders of the portfolio. If some doesn’t compete, we’re looking for opportunities moving out.
I wouldn’t describe we’ve got anything significant inside the portfolio today that would fall into that category. And we’re always looking and trying to be opportunistic, which I think describes to your point, the APLNG ROFR and the Surmont ROFR that we hold. So you never quite know when your partners make a change that you didn’t anticipate, and you get a great opportunity to acquire an asset that you know really well. And the one that we know we can make better if we have it under our control, and ultimately, as I said, it makes our 10-year plan better. So we’re always out looking to find — because you never quite know when these things might materialize, but we tend to be very opportunistic. And I just remind people, our framework is intact.
It has to meet our financial framework. We got to see a way clear to make the asset better, and does it make that 10-year plan that we think is quite compelling, does it make that 10-year plan better, which is a pretty high hurdle inside the company.
Operator: Our next question comes from the line of Paul Cheng with Scotiabank.
Paul Cheng: Can you hear me?
Ryan Lance: Yes, we sure can, Paul.
Paul Cheng: If I can go back into Permian. What’s your average lateral length now? And then how much do you think you can improve or lengthen it over the next several years? Is that the — one of the primary contributor that you think you could improve the result in your OBO, Permian operation. And also that, whether you guys have tested because at some point, I would imagine it will reach this economy of scale when you get longer and longer. Do you have any experiment that you guys have done that, what that limit may be? Is it 4 miles? Is it longer than 4 miles or less than 4 miles?
Ryan Lance: Yes. Thanks, Paul. I can let Nick kind of weigh in on some of that. We’re not, yes, I think lateral length is just one of the things that we’re working on. Nick described a bunch more on an earlier question around completion efficiency and how we’re attacking the spacing and the stacking. So I think it’s all of those things that we’re trying to attack, and they’re different depending on where you’re at in the Bakken, the Eagle Ford or the Permian. But we have deep experience in all 3 of those basins and using all that knowledge to make sure we’re maximizing the recovery and minimizing the cost of supply, and maximizing the efficiency that we’re getting out of it, specifically on lateral lengths, I can let Nick weigh in on that.
