Sable Offshore Stock

Hello, and welcome to the Sable Offshore Corp. Investor Update Call. [Operator Instructions] Also, as a reminder, this conference is being recorded today. If you have any objections, please disconnect at this time. Harrison Breaud, you may begin.

Good morning, everyone. My name is Harrison Breaud, and I'm the Vice President of Finance and Investor Relations for Sable Offshore Corp. It is my privilege to welcome you to this investor call this morning. At this time, I would like to introduce our Chairman and Chief Executive Officer, Jim Flores; Executive Vice President and Chief Financial Officer, Gregory Patrinely; and Executive Vice President, General Counsel and Secretary, Anthony Duenner, who are all with me on this call, along with various other members of the Sable team.

On this call, we will provide updates to our investors on recent events pertaining to Sable Offshore and take questions from analysts and investors. Our sell-side analyst community is welcome to raise their hand in the webcast to ask live questions. And our investors are welcome to submit questions in writing during the webcast as well. Sable will not announce the names of the investors who submit questions in writing.

We recommend that investors reference our most recent investor presentation posted to our corporate website on June 1, 2026, during the call today. That presentation may also be referenced by management, by page number throughout the call. Please reference the disclaimers page on Page 2 and read them as well as the additional disclaimers throughout the presentation for your protection.

I will now hand it over to Jim Flores to begin his prepared remarks. Jim?

Thank you, Harrison, and good morning, everyone. We've been out talking to investors at an energy conference and throughout incoming phone calls and so forth. And we've been going through our business and we've had several updates to give everybody. So instead of trying to do a piecemeal, we're going to do it in this conference call. There's some confusion around our offtake strategy at SYU and Las Flores Canyon, we want to clear up because we're producing at high rates out of Platform Harmony and Heritage. We've got Platform Hondo coming on.

Operationally, fields performing spectacularly. We're not seeing any decline rates. We will see some at some point in time, but our engineering forecasts are proving way too conservative. And so we're very proud of that. And we're talking about value to the company and security, there's a lot of concern in the investor community about our offtake options.

Obviously, our SYPS pipeline being federally authorized by the Department of Transportation and PHMSA and is proving to be our best route and we're continuing to use that in getting our oil down to Chevron refinery in El Segundo. The aspect of that is based on the DPA, the Defense Production Act that Trump administration authorized for the Secretary of Energy, Chris Wright to sign and keep that production going and it's working just fine.

There's a concern if something happens in the DPA that what are our options and I want to reiterate that the DPA orders us to use the SYPS pipeline. That's the only authorization that the DPA does. So if the DPA falls away and the SYPS pipeline, for some reason, a bad legal ruling or something is unavailable to us, then the OS&T permit is automatically activated. That was the deal Exxon, our previous operator cut with the state is that as long as the pipeline is available, the OS&T permit just sits there. But if the pipeline is not available, the OS&T permit is immediately active.

So we have that in our back pocket. This is a $10 billion to $30 billion value oil field. We're going to produce every barrel we can out of this oil field, especially for many, many years and decades. And so having that backup plan is really important to us. And again, that OS&T plan costs about $500 million. The OS&T plan is about hookup and logistics of a facility that processes all the crude offshore instead of currently sending it into Las Flores Canyon where it's processed onshore. And by doing that, there's a lot of smaller FPSO, OS&T vessels around the world that are constantly coming off production. They're used, that can be put in service with some minor modifications. So we know that's a fast-track situation of 10 to 12 months as far as getting that done if it's required.

So although it would be an interruption, it would not be a door slams in our face with no opportunity for production and it does cost $500 million. So in the interim, we also came up with our buoy marketing strategy where we would have to lay a sales line from our Las Flores Canyon midstream processing facility offshore to our Platform Harmony and then eventually to a sales buoy that would be located south of Platform Harmony for offtake of tankers of processed crude. That crude will be processed just like it's being done today at Las Flores Canyon, basically water separated and so forth and gas being diverted.

So we would use our existing onshore facilities and go to buoy. The key on that is that the acreage from the beach out 3 miles, the state waters would require a right-of-way permit, and we think that would be difficult to attain with our relationship with the state at this point in time. We think we could take advantage of a designation of a strategic petroleum reserve back up at Pentland in Bakersfield. And so we have proposed that idea to the administration and DOE and I'll cover that a little later, but that would give the ability for the federal government to give us rights of way across state lands and state recreational areas that would secure the pipeline for the buoy strategy that would allow us to prosecute that as well.

The buoy strategy has tremendous marketing upside. As we've disclosed to all investors, our differentials right now are about $17 a barrel to sell oil from our Las Flores Canyon down to El Segundo and additional $3 of transportation for a $20 all-in cost structure. The maritime discount is more like $7 to $8. So we could pick up possibly $10 or more per barrel. When you multiply that times 20-some-odd million barrels of annual production, talking about $200 million in additional cash flow. And the buoy strategy would cost us about $125 million. It breaks down to have $75 million worth of pipeline, $25 million worth of [indiscernible] and buoy and then $25 million worth of pumps, compression, valves and et cetera.

So with that, that's a very economic marketing angle that we could take advantage of with the advent of the SPR up in Pentland that would give us the opportunity for to get our right of ways from the federal government versus having to get from the state of California. So pipeline first, everything is working great. It work fine on that. We're processing a lot of crude. We have great infrastructure, Las Flores Canyon and the pipelines are in good shape. We have a lot of capacity to fill up there as well as all the way back to Pentland. And so getting back to Pentland, we're proposing a strategic petroleum reserve in conjunction with DOE and meeting with the Trump administration.

And what we're trying to do is provide ample inventories for all the existing refineries. It's not a secret in California, all the refineries have been under siege in California, and there's a lot of stress in the system because there's no strategic petroleum reserve. So the reserves all have to be kept on their books commercially for the excess for the refineries put extra cost burden on the California refineries, say, versus the Gulf Coast refineries. And so they become noncompetitive.

So with the 6 SPR locations in the Gulf Coast supporting the huge number of refineries in the Gulf Coast, we at least have one in California that would help support the 6 refineries that are out there. All the producers in California, us included the customers to sell our crude. Right now, there's severe stress in the San Joaquin Valley onshore producers because of pipeline capacity and offtake and obviously, lack of customers. SPR will go a long way toward alleviating that. There's 560,000 barrels of pipeline capacity and truck capacity coming into the Pentland station. And there's 560,000 barrels of offtake and pipeline capacity coming out of Pentland to the refineries. And right now, I think we're somewhere around 140,000 barrels a day of utilization.

There's a tremendous amount of uplift there. There's going to take some work of connecting some pipelines, some right of ways, some permits and so forth. That's why the SPR designation, which would give the Secretary of Energy full condemnation rights to prosecute a plan of having oil from the production point getting to -- through the pipeline infrastructure, getting to Pentland and then the oil from Pentland getting through the pipeline infrastructure to the refinery and thus the customer.

So there's never been a comprehensive redo of the pipeline infrastructure back onshore at Pentland and delivery, and this would give the opportunity for the industry to make it efficient and serve all customers, all the onshore producers, all the offshore producers, all the refineries and make it much better on the California consumer and much more secure for the U.S. military. So we're working very hard with that. We've gotten a great reception on all fronts. It's just a matter of getting everything done with as busy as everybody is up in D.C. And so we're looking forward to having a busy time period coming up here to try to get that over the line and work with all the stakeholders on that.

But I can't stress how positive that would be for the entire California energy system out there from consumers to producers all the way across and refiners as well. So take care of it. Hope everybody saw that Erin Burnett show last night in CNN where they documented our field trip with Secretary of Energy, Department of Energy, Chris Wright and also Secretary Doug Burgum of Interior. They came out to Las Flores Canyon and flew out to our SYU Platform Harmony. And I thought the coverage is fairly fair there. So I appreciate the CNN.

On top of that, the next deal I want to update is the court hearing in Los Angeles on Monday. We just had in Judge Wilson's Court. The transcripts are public and they're out at www.cd.uscourts.gov/court-reporting-services/court-reporting-recorder/transcripts. Now they won t let me send it out. So you can look at www.cd.uscourts.gov/court, and you can figure it out from there to get it done.

Please read those transcripts. They were very enlightening as far as some of the challenges because we have 2 sets of litigation. We have a litigation where Sable is suing the Coastal Commission and Santa Barbara County for over $450 million of recovery. All the delays and all the roadblocks they put up when we're fully permitted, we're documented, Santa Barbara County acknowledges that and so forth. And so we're operating under existing coastal development plan that's valid. And so we're looking forward to prosecuting those cases against those 2 entities for the full of the recovery.

Then there's the challenges of our federally administered asset pipeline that's under federal jurisdiction under Department of Transportation and PHMSA is being challenged by the state of California where the pipeline is the definition of interstate pipeline goes from federal waters offshore onto California state. So it's 2 parties. And we've gotten all the approvals for that last year prior to any kind of legislation that they tried to pass as well as the Chris Wright's DPA authorization and the aspect of DOT and PHMSA and then also the DPA all being heard in Judge Wilson's court, and we look forward to hopefully a resolution -- resolution on that, but it's the U.S. Justice Department defending us and the federal government against the state.

So we'll see where that goes. If some reason, I'm sure the -- whatever the hearing is, whatever the outcome is, it will be quickly remanded to the Ninth Circuit Court of Appeals on an emergency basis. And so we will move through the courts pretty quickly either way. But that is in no way stopped our production at this point in time. In fact, Judge Wilson shut down 2 attempts to have a preliminary injunction on our production prior to the hearing on Monday, both with the Enviros and also with the state and the state, [indiscernible].

So those 2 as well. So we continue to roll along and with the confusion out there, we want to make sure we had a chance to talk about what our plans forward are, but also what our solid footing is. Our refinancing efforts toward the Exxon note are going quite well, and JPMorgan is leading that effort. And that's all I can say about that. So you can talk to JPMorgan if you want any details on that.

And so with that, I'll open it up for questions or any comments?

Sure. So we'll move to Q&A now.

I think first, we'll call on Charles Meade of Johnson Rice. Operator, if you could unmute his line, please.

[Operator Instructions]

Our first question will come from Charles Meade with Johnson Rice.

I guess that was the important part, Jim. Let me add. Thanks for laying out all this -- the context on the SPR. One question or this SPR strategy, one question, how would you encourage us to think about the timeline for that to come to maturation? Because it really seems -- once you identified that as a possibility, I think I, like a lot of other people went back and looked at the EPCA and it looks like it's just -- it's a perfect match for what you guys are trying to do. But I don't really have any sense for how long it might take you to doing that?

Yes. Great question. The DPA, which we had to kind of go back and create the situation and validated from the Department of War needs and the military readiness preparedness and the INDOPACOM requirements for making sure we got enough jet fuel in the South Pacific in case something kinetically happens and so forth, all that justification and then going through the Justice lawyers, the White House lawyers and the DOE lawyers, that took about 9 to 10 weeks for the DPA, okay?

So in this case, with the Strategic Petroleum Act of 1975, it's adjudicated law. So just following that law and applying it to California, it should take a lot less time. But this is still -- so we're in weeks and a couple of month or 2. Hopefully, we can have this resolved this summer. That would be the expectation. And then we would immediately go into the work of the condemnation and granting -- getting all the pipelines hooked up this year. And then like basically what the condemnation would do is you condemn like a tract like the Gaviota State Park, make the appraisal on that was like under $700,000. You would pay California $700,000 and then the federal government would grant a perpetual lease for the same price. We paid $700,000 for it.

But once condemnation is filed, it's condemned, you're just arguing about the price, and we've already done the appraisal on that stuff. So we're not talking about much money. Around Pentland itself, it would be immediately connecting pipelines to tanks and making sure we have the most efficient system, and you could grow it to whatever you want. Right now, there's about 370,000 barrels of storage at Pentland. You can grow 30 million to 300 million barrels if you need all the surface. So that's all to come.

The first is the designation of the SPR condemnation, get done, and then you would go to Congress for appropriation to actually construct additional tanks. And you'd obviously have to go to Congress just like you do in the existing SPR for fill to make sure you can purchase the oil. So it would be an appropriations deal going forward. But the initial impact to debottlenecking Pentland and the Bakersfield pipeline system for all producers onshore and offshore would be like very quick this year.

Got it. That is great additional detail. And then, Jim, earlier this week, there was -- maybe it was yesterday, there was some news report that the California Coastal Commission had sent you guys another letter saying that you're moving towards holding Sable in contempt. Can you share -- is this the sort of thing that would get rolled into the existing cases? Or is this going to be a new -- could this be some kind of new line of objection?

No, it's exactly what. It's just a love note from Coastal Commission. It's all it is. It's rolled into our case, which case is right here?

Sable has sued the State of California, Pacific Pipeline company versus the State of California. It's in federal courts, United States District Court for the Eastern District of California. And it's #7 on that list. So it's challenging the state's passage of -- it's called Senate Bill 237. So we sued back in 2025. And so basically, the California Coastal Commission is sent us that letter. We don't have to reply to it because it's this lawsuit, and they're just trying to prosecute their administrative judgment.

We're looking forward to taking depositions to the entire California Coastal Commission once we get the federal court and get through this because we're suing them for $350 million of damages. So this is just their harassment back to us based on that -- based on the reaction to that lawsuit. But it has no effect on operations. And it won't and may subsequently try to levy fines administratively, but it's not going to be we're going to be [indiscernible].

Our next question will come from Emma Schwartz with Jefferies.

Good to see Jim and Caldwell earlier this week. What I want to ask a little bit about is the dynamic on the differential side. Could you talk about like the relationship with the refineries and how that's impacting differentials across the Board in kind of California and where you see that kind of going? And is there any changes that we should be expecting there?

Yes. It's a great question, because I've had a long history in California and so forth. And when all the Alaskan crude coming into the West Coast and pounding it, differentials were even much wider than they are today. So what happens is when you lose a couple of refineries like the Wilmington Phillips 66 refinery shut down and then Valero shut down their Benicia refinery, then you have -- that crude supply has to find a home with the remaining refineries.

And so the benefit goes to those refiners and therefore -- and they're going to and to reallocate that crude is going to take some money and logistics moving around and also some testing and so forth. So the difference is widen. So that's the market working right there. I think when we debottleneck the midstream system with Pentland and SPR and getting more of a stable platform where we might be able to reactivate those 2 refineries.

We have a lot of entrepreneurs out there trying to figure something out on those. They're 2 fantastic plants, but you have to have a lot of cooperation from the federal government in the form of the SPR and also maybe working with the state to get it done. Having more refineries and more demand will bring those differentials in. That's why our buoy strategy is so exciting. We'll be able to market our crude around the world theoretically. And once you have that outlet, then even local refiners have to respect that to buy our crude.

So we have a strategy to bring those differentials in as long as we're going to be out there, we're taking a really long term to make sure that we're in good shape. Again, I think the best opportunity for the onshore producers is the SPR debottlenecking and get more crude moving out of the basin, into the market, and so we can -- they'll all level out. So it's going to be a year or 2 getting this figured out, I think, but we'll see what happens.

Got you. That makes a lot of sense. And then it's just like a second question. It's really good to see the transcript from Judge Wilson from the hearing earlier in the week. Could you walk me through kind of the time line for that case and where you think that one is going and kind of on the DPA side, on the legal side related to that, where is that kind of heading there?

They're all in Judge Wilson's court and the Justice Department did a phenomenal job defending the United States and also Sable as well as our lawyers. I think our lawyers all ex justice as well. But anyway, it was quite a show of power. And it was a very straightforward. The wonderful thing about federal court is you have to follow the law. We found a state court in California, there's a lot of interpretation in what the law meant and things like that. And there's a lot of bending with political, they're all elected and they're local and so forth.

But we're real pleased with the shakes on the federal side, and we're looking forward to continue to clear it up. I think we'll look around a year from now and go, wow, that was probably any time. But it's all about federal supremacy law and making sure that a federally operated pipeline under federal jurisdiction can be federal laws applied to it.

So we're continue to press that mantle forward and I think it's going to eventually be the one. So the timing, federal judges weeks, months on a ruling and then I'm sure there'll be appeals and everything will be done on an expedited basis, but we're pretty happy by spring of next year having a lot of stuff behind us. The ones we're excited about is the ones we're pursuing the Coastal Commission and Santa Barbara County to make sure we can prosecute those to get that money back for our shareholders.

Thanks for the keywords [indiscernible].

Our next question will come from Michael Furrow with Pickering Energy Partners.

Just one for me on the refi, and I recognize you may be limited on what you can share at this time, but obviously, it's topical given the quickly approaching maturity time line. Jim, I agree with your comments that the transcript offered some potentially positive developments on some of the Monday's court hearings. And I'm not asking you to provide a legal opinion, but it does seem like an underwriter's risk tolerance could be impacted by the outcome of these cases. And from what we can transcribe from the transcript, it seems like the next hearing may not be until June 25, which really doesn't give enough time to have incremental information be considered for the underwriting process.

We know that Exxon's worked with the company in the past. And so if you could, I'd be curious to hear around the options that the company has at its disposal, specifically to the June 26 maturity date.

Well, let's be clear. Exxon has been our biggest sponsor. They obviously -- we worked hand-in-hand with them. They granted us an extension last -- in the fourth quarter last year to March '27 with the accelerator being we have to pay them off after 90 days of sales and so forth, which we fully intend to do that. But we couldn't have more -- a better and more respectful relations with Exxon and appreciate everything they've done for our company.

I'll turn it over to Gregory for the financial aspects of it.

Yes, Michael, thanks for the question. Look, as we discussed on our call last Monday, we are very much focused on debt capital markets solutions to handle all of our obligations, including the upcoming maturity on June 26. And we're making great progress on that front. Those efforts are led by JPMorgan, as Jim mentioned. And as always, the optimization of our balance sheet and the lowering of our cost of capital, that's going to be a focus, and that will remain a focus going forward. And so I think we've made a lot of progress on that front. Yes. And just for another fine point, Michael, we're not at full power in the field. We don't have Platform Hondo 1. That will be full blast by September 1. We're ramping up. We're looking -- we issue look for kind of a bridge loan like situation. So that's kind of what this next financing hopefully will look like some kind of bridge type terms.

And then we'll get on to possibly refinancing the balance sheet and a real advantageous showing the reserves sometime next year. So we're excited about our process and see what happens.

Our next question will come from Noel Parks with Tuohy Brothers Investment Research.

Not being super familiar with the sort of legacy SPR operations in the country. I just wondered, would there be contractual terms of how the new SPR capacity that you're looking at, how that storage would be filled? Or is it essentially discretionary at sort of the administrator s prerogative? And also, if you have any insight on pricing, I'd be curious about that as well.

Yes. No, the facility will be owned by the Department of Energy. It will be authorized by the Department of Energy and paid for by the Department of Energy, all through Congress appropriations. They do have contractors for like a 1% fee that operate the 6 facilities in the Gulf Coast now. But it's all deemed basically on funding available and how they want to fill it and what pricing. I mean I think the pricing -- it won't be a refinery dip. It will be attracting barrels. There will be pretty tight pricing going forward.

But you're probably 3 years from now filling that by the time you get it appropriated and built where you actually be able to put I'm talking about new tanks and stuff like that. The existing tanks, we work with them on, we can fill that sooner rather than later. But I don't think it's going to be a big impact to the pricing market. The biggest thing it's going to do is by debottlenecking all the pipelines and coordinating. We had this tremendous California oil industry for 100 years out here. There's kind of pipes going everywhere, but some -- any one person or any one company had control of everything to make it all connect and make it all efficient. This would have the effect of having one group over it and connecting all the pipes and the tanks for the common good and efficiency of market.

So it's going to help a lot as far as going to get California-based crude oil to the refinery market and the refineries know that's out there, so they can actually -- you could restart Wilmington, you could restart Benicia based on the size of the SPR knowing that you had a crude oil supply that didn't have to be imported. So it's got a lot -- the pluses there are all on the side to the refiners from a standpoint of the marketing. But the big impact to the producers is going to be the ability to get their crude to market versus trucking and that type of thing.

Great. And with the buoy option, I'm just wondering given the, I guess, greater variety of offtake options you'd have from there, would there be any effect on your ability to hedge production if you were relying on the buoy options, either just in terms of the physical logistics on the physical side or just financial coverage?

No, no, there wouldn't be because we'd be selling right there at the buoy. There's 2 buoys offshore California now. There's one to Long Beach and one in El Segundo. I think they have a spread of 3 offtakes per buoy and so forth. We hedge just like we would the buoy would be a point of sale, just like our valve at Pentland point of sale. So we'd be hedging same thing. We just have -- we have a better look at the world market or differentials versus the captured in-state market in California. So we'd be picking up that differential uplift, but it operates to be the same, right, Greg?

Yes, that's correct.

This completes the allotted time for questions. I will now turn the call back over to Jim Flores for any closing remarks.

Yes. Thank you, operator. Thank you all. We thought it was important to get our plans. They're very definitive out in the market and continue to press forward, and we're looking forward to having a great year at Sable. Thanks so much.

Thank you for joining the Sable Offshore Corp. Investor Update Call. You may now disconnect.

Hello, and welcome to the Sable Offshore Corp. Investor Update Call. [Operator Instructions] Also, as a reminder, this conference is being recorded today. If you have any objections, please disconnect at this time. Harrison Breaud, you may begin.

Good morning, everyone. My name is Harrison Breaud, and I am Vice President of Finance and Investor Relations for Sable Offshore Corp. It is my privilege to welcome you this morning to this investor call. At this time, I would like to introduce our Chairman and Chief Executive Officer, Jim Flores; Executive Vice President and Chief Financial Officer; Gregory Patrinely; and Executive Vice President, General Counsel and Secretary, Anthony Duenner, who are all with me on this call, along with various other members of the Sable team. On this call, we will provide an overview of the new investor presentation that was posted on our corporate website this morning and take questions from analysts.

I will now hand it over to Jim Flores to begin the presentation.

Thank you, Harrison and roll to the next slide, please. The disclaimer, everybody can read that the leisure for everyone's protection. Then on to Slide 3, which is the introduction of Sable Offshore Corp. This today will be our most comprehensive report on Sable. We've owned that you for several years now. We've done extensive geologic studies and engineering studies and production studies and so forth, and we feel like we have a really good handle on our asset and the way to many years of profitability going forward.

But the backbone of our company is the 15.5 billion barrels in place and extracting over 2.2 billion barrels recoverable with about 1.5 billion barrels of total remaining reserves. And it's going to take many years to recover it and so forth, but we have a great plan we're going to outline today and going forward, at least for the next few years to getting a position to do that.

We created a lot of value with SYU on the PV-10 strip of about $6 billion. Exxon developed a field and built everything there as -- and when we bought it a few years ago to take it and put it in our Flame acquisitions back and also in later Stable offshore corp. And many of the equity partners on the call understand all this history and the Santa Ynez pipeline system where we repaired the pipeline system and got all the federal approvals for restart and they've been producing in the pipeline since March under the DPA that -- the Defense Production Act that was ordered by the President the United States.

Our platform is Harmony and Heritage began flowing in May of '25 at very low rates, just to make sure that we target all the equipment working because we weren't able to sell. We were continuing to bank all in the 540,000 barrel tanks and Las flores Canyon waiting on our transportation green light with the Defense Production Act, which came in March of this year, we've been ramping up production ever since. Production this morning out of the 2 -- just 2 of the 3 platforms is around 46,000 barrels a day.

Sable is currently pursuing refinanced with Exxon term loan, which is ceded to mature in June of 2026, and our bank JPMorgan and spearheading those efforts.

Page 4, please. The history of SYU began with Platform Hondo with a single platform and an offshore treating and processing vessel called OST, that was barging oil out and so forth and made 160 million barrels, and then in the early -- late '80s, early '90s, they're able to expand the operating footprint with Las Flores Canyon where all the processing be brought onshore, and then also the installation of Platform Harmony and Platform Heritage and associated pipelines as well as the pipeline, the Santa Ynez pipeline system that goes back to inland for sales. And that allows the field dramatically increased production of about 115,000 barrels a day. And then as they would have it, instead of supplying the California offshore market here he came to the doorstep for Alaska in the 80s and basically became the overwhelming fuel for the West Coast. And so the development of SYU was idled by Exxon until after the Obama administration limited the export ban in 2010 and in 2012 -- '13 and '14 started drilling some wells and just about 5 wells drilled, the Plains pipeline, which is now our SIP pipeline, had a rupture and was shut in for 10 years. We've reestablished the production on that and we're going to move back to the full field-wide development. That's why you going forward, you'll see.

So on Page 5, assets -- the leases in yellow, that's our unit. This 1 single unit called Santa Ynez unit. It's operated we were in conjunction with the euro land management was Bom and Besi under the Department of Interior and federal -- all federal water, you see the state waters are in light blue, where our pipelines crossed our loss toys Canyon and then this pipeline continues all the way back to Pentland and then on to the Los Angeles refineries. The SIP's pipeline now begins at Platform Harmony and Federal waters and goes through the state waters on the state. And therefore, it's defined an interstate pipeline by Department of Transportation and their PHMSA group as a jurisdiction over. The total federal leases of 76,000 acres. We currently, we're selling all through that pipeline to Chevron's El Segundo refinery. There is additional marketing optionality. And as you recall, in the last year, we've pursued an OS&T strategy where we moved the processing offshore and then try to offload like 1 of the international cargoes into the international maritime market. We've since refined that plan instead of having extensive offshore facility we're going to -- we added a pipeline as part of that strategy from Platform Harmony to Las flores Canyon to where we will still send all of our all of our crude into Las Flores Canyon for processing, then we'll export it out of Las Flores Canyon instead it in the existing sits pipeline with the extension of the SIP's pipeline out to Platform Harmony for sales in a traditional buoy like they have down at Long Beach and El Segundo has much less expensive since all the processing is already in place at Las Flores Canyon. And that process is about $25 million for the buoy, $75 million of the pipeline and about $25 million of the pipe's valves at Platform Harmony for modifications. So for $125 million, we have a secondary outlet besides our existing SIPS pipeline in case anything happens either operational or regulatory or in the refinery market continues to collapse and in California does get turned around. Whatever might happen, we want to have access to the maritime market. This is going to take some approvals from DOI and Babesia discussed with work through all those processes. And I would say also as far as airport, but it's actually -- there's no net increase in that other than the tankers company going like Long Beach because we're using the same processes. So it's a low carbon low emissions strategy of choice for us. And then, of course, we'll need Department of Commerce to oversee some of the regulatory obstacles that California will try to put up. So we're very familiar with all 3 of those outlets, and we work handily with them and we look forward to pursuing this body, but it's a very significant part of our strategy to derisking whatever might happen regulatory-wise from California.

Back to the asset on Page 6. We want to write -- so and as far as all the major fields in the Gulf of America, and of course, West Coast and so forth. And we right fourth of remaining of cumulate production also remaining reserves to get out of the ground. So these are -- this is -- just shows you where we rank some of the biggest deals of the world. And from my career, the some of the East Bay fields and Main Pass 6 fields to make this list, and there were some of the biggest fields I've ever seen. So this is obviously the largest project I've ever dealt with and as far as remaining reserves that we're looking forward to taking advantage of.

Next slide, Page 7. With the 77,000 acre reservoir and multi-tier production in the different zones the oil in place calculated by the engineers is 15.5 million barrels. The total recovery of 14%, which is a very low recovery rate. But that's what we're going with right now is 2.1 -- 2.2 billion barrels, excuse me, and it's produced 671 million barrels a day. So total remaining reserves is 1.5 million barrels and our primary forecast of 894 million barrels is basically in the non-fuel pays an upper solitons and the massive chart. Then we have the heavy oil forecast. This is below 13 gravity oil. Exxon, our predecessors, drilled a couple of wells the oils viscose, it flows. We just don't know how far down the reservoir goes. As far as has been tested, we've established million barrels of recoverable oil 13 gravity oil, but it could become much larger, and that would increase -- that would push our total ultimate cover closer to 20%. So that's going to be a big part of our big part of our identifiable efforts of value going forward. And it takes on rates in some of our processing because the heavy oil takes a lot more separation and so forth to process. So that's on the horizon beyond our remaining forecast that we have right now in the primary.

On Page 8 is an update -- really an update slide. I'll remind everybody about our sit pipeline and our processing facility at lass. It's all been hydrotested much higher pressure than operating pressure, but fully hydrotested and remember that our total max capacity is 150,000 barrels a day. So we have plenty of capacity. If we want to add another platform out to the east, it gets some more reserves beyond the 3 platforms we have. Right now, with production ramping up since May of '25. We have 22,000 barrels a day out of Platform Harmony and about 30,000 barrels a day of heritage a little higher than that today with 46,000 barrels a day we produced we're producing now. And our Platform Hondo has gone under extensive renovation. This is a 50-year-old platform. We've done some structural work we've done with full instrumentation and so forth. It's scheduled to be on by mid-summer. And we're doing several of our initial per pads at Hondo. I think it's 9 of them there, and then they've been coming in at 800 to 1,000 barrels a day. So it's really enhancing production there. So we expect another barrels a day or 10,000 to 15,000 barrels a day out of Hondo and we get full production by early fall.

Page 9, our development plan. This plan was to maximize free cash flow. So based that minimize our spending. As you can see, we start off with 129.4 million barrels at the end of '25 beginning of '26. This plan fully replaces all the barrels that we produce over the next 4 years to per fats, which are basically dropping tubing guns down the tubing and additional perforations and unparked loans in the existing reservoirs, very minimal and so forth, very low cost. And the average across the 4 years of $0.64 a barrel replacement cost. You can generate a lot of cash flow and you only have to spend $0.64 a barrel to replace all the reserves and these are basically moving PDNP reserves to PDP. So we're just talking about our PDP reserves. So from a credit standpoint, having the same number of barrels 4 years from now we have today, we're spending this minimum amount of dollars is a spectacular position. The same thing we did onshore PXP for 15 years, where our reserves didn't change for 15 years. We make sure we maintain our reserves through the same type of activity when parkade was team optimization in that case. But in this case, it's straightforward. We've actually -- put the page to next page.

Page 10, we've actually conducted 2 of these operations. And you can see on here, Sales, the third bullet, we were 250 -- 280 barrels a day, respectively, now they're 900 to 1,100 barrels a day, prospectively. These spectacular intervals to shoot that's just left behind pay that we harvested because it was too premature in the fields life when Exxon had produced a product in 2015. You can see that rolls off with our perfect inventory of 56 remaining per pad. So we have 2 already done. We'll do more in and then we'll do 10 more in '27, 7 more in '28 and 15 more in '29 and with 50 more remaining after that. There's also in '28, we're talking about adding 8 ESP pumps. As you recall in the IPO, that was 1 of our initial strategies that we thought we'd have to institute immediately, but the pressure in the field has come up about 25% to 26% from where it was when we shut in based on just geologic forces like water drive in this big reservoir. And so with the pressures in the field, we've had immediate rush to go out there and try to assist flow rates with the ESP. So basically, the pressure will drop eventually where it drops. We think at this point in time, we think 2028 is probably the point in time where we could start to get some benefit of adding additional pump capacity out there, and that's what we have for ESP. If we've done a until '29 push the ESPs back. If it happens earlier, and we need to support our production and our reserve replacement, we'll move forward in '27. So that's our safety valve to make sure we hit our plan on the previous page, Page 9, with ASPs in our pocket, plus our remaining inventory of 15 years per fads to add to it before we put a drilling rig out there. So each 1 of these paras and each 1 of these ESPs million barrels to the PVP line of the company. So it's very, very important.

The illustration on Page 11, is our cross section, and you'll see the existing parks in red, and they're in the massive chart and right top of the lower carriers and so forth. And the upper Solicitous zone as has had very few wells and it's very likely tested across the 77,000 acres, but it's very, very prolific. So we're going back and adding perforations to the existing perforations. We're adding those in the upper solutions. Those are the cheap 56 perf add that we're talking about. And maybe a couple on the massive chart where the perforated low in the section. But this is this oilfield 101 and basically a big, large production fuel management. The heavy oil upside, we'll draw sidetracks at some point in time and on produce that as well once we do the facility modifications that we're able to handle pool, but it's a tremendous part of our story going forward for years and decades ahead. The long-term opportunity -- this is our initial upper solicitous drilling, 100 wellbores here. We have multiple additional locations in the master chart. And of course, the heavy oil leg will cause safely redrilling of the field on a proved basis. So we have a lot of drilling to do this beyond the initial production phase and maximizing cash flow that we look forward to, depending on the economics and prices going forward.

On Page 13, we have the reserve estimates at Brick. This is a fully operational plan where we have rigs in the field. It's not a PDP blowdown like the reserves we showed earlier with a lower amount, so you get more PDP reserves, the field life by keeping the LOEs lower because of the production volumes. So you can see how we'll play out in the value way we're going to create going forward. This is a very low-risk plan. It's all within our platform reaches and rigs and so forth. And so just depending on prices of where it goes and where the value ends up for our company.

All right. On the legal side, Page 14, we've been covered on our pipeline -- export pipeline in SYPS by the federal consent decree, which was the settlement agreement between the pipeline operator PAA and the federal government and the state government and all the state agencies, so forth and local agencies and require certain aspects of prepared work to be done for the pipeline and testing, the hydro testing and so forth before it can get for the operator can restart. We inherited this consent decree. We've implemented all the repairs. We did almost 200 gigs in the repairs with off the fire marshal the governing body for California's personnel standby with us. We've worked with them when we report to the head fire Marshall that's in Sacramento and so forth of accomplishing everything. And at same point in time, we do attract this to PHMSA because of the addition of the federal pipeline offshore with our state pipeline we thought this -- we could nominate this as an interstate pipeline. PHMSA agreed. PHMSA gave us interstate pipeline status in December and gave us a permit to restart the pipeline based on the work we had done that they independently reviewed and so forth and gave us approval to go forward as an interstate pipeline under PHMSA jurisdiction. And so forth. So basically for there, the Justice Department has moved in force of a consent degree as them were complete where the consent Decree has moved to federal court to get dissolution of the federal Consent Decree and the first hearing is next Monday on June 8, and we're optimistic at some point in time, that justice will prevail and get that dissolve. So the aspect is it does apply to us now from the PHMSA ruling and also the DOT and also, of course, the Defense Production Act that becoming an interstate pipeline allows the President the United States to order the Secretary of Energy to declare Defense Production Act to immediately start producing oil at maximum rates through the SYPS pipeline system. And we did that about 75 days ago.

That all rolls up into Page 15. This is current. And what's happened now is, obviously, California has had some heartburn over our Federal decrees and Federal Defense Production Act and the Justice Department, our legal group here at Sable well as our outside counsel have been working hand in hand forward, clearing that up and getting that straightened out. And we continue to have good results there as the federal law applies and supremacy law is very effective here as far as realizing that the federal government has free of the right to own the estate.

Moving on from there, from Page 15 to Page 16. The milestones we've achieved as we completed the repairs to the fifth pipeline, May of '25, we restart production platform in May of '25 and complete successful hydro test of SYPS in 2025. And those hydro tests are key because you put under amidst pressure beyond operating levels, can you make sure the pipeline has got 100% integrity, which ours do. Resume oil transportation through SYPS the LFC midstream processing facility in May of; 25, where we're banking the crude and our tanks ready for the journey back to Pentland so we can start selling it. the fellow regulatory oversight in SYPS. I talked about getting the SYPS pipeline confirmed with Interstate Pipeline December '25, Defense Production Act, March '26, resume Petroleum Transportation, Food segments. 2024, 2025 was SYPS to March of '26 back to Pentland, which is our sales point back the South of Bakersfield. First sales to Chevron, it ships March '26, I think I have 1 day of sales in March, right, Greg?

2 days.

2 days, but it was significant around here. It was our first sales of 5 years. And then we had a restart production platform heritage April '26. That's where we are today, and we won't have as much production in the history as possible for -- we want to go out in the market and be able to communicate all our potential stakeholders about the refinance of the Exxon note. So we're refinancing the senior debt spec year June, commenced commodity hedging program June '26. We start production platform on do, that would be third quarter of '26, and that's the platform we're having to really refurbish but also as the 9 perf adds, that a big part of our production. And the potential sale oil sales by Santa Ynez Unit, we have some regulatory -- federal regulatory hurdles we must get. That's why it was put potentially, but that's a big part of our process. on the buoy because it will help -- it will give us a secondary outlets, so sales security, but also allow us to capture some of the maritime premium versus some of the onshore differentials that we're seeing in the market now because of the lack of refinery capacity. And then continually can protect stable specificity to pursue all monetary damages. We have about $450 million worth of lawsuits against commission in Santa Barbara County that we're continuing to pursue with vigor. And we feel like we'll have restitution at some point in time.

Okay. I will turn it over at this point of time to Gregory Patrinely, our CFO, to do the financial overview of the current capitalization on Page 18. Greg.

Sure. Thanks, Jim. So on Slide 18, this is our current cap table. And Jim laid out the massive reserve base that we have and the low-cost structure including the kind of unheard of finding and development cost to maintain flat PDP that all leads to very, very robust asset coverage. If you take a look at our PDP, the net reserve coverage columns here, 2.6x on net debt on PDP alone, 5.8x on a proved basis. and then a first 3P estimate at 6.7x. And just backing up on the reserve report itself, we plan to have a full 3P Netherlands Sewell reserve report at year-end with the filing in conjunction with the filing of our 10-K in 2027. So we look forward to continuing to work with Netherland Sewell on that front. Today, we also posted our preliminary Netherland Sewell proof of course. That report focuses on the existing wells. That's the PDP wells from the platforms, Harmony and Heritage, and then the PDNP from Platform Hondo because Honda is not online yet. We fully expect those wells and those reserves to be PDP, which is what's reflected in this table.

Yes. One comment about our report, there's not enough production history on the wells to be fully unrisked by Netherland Sewell. They still have heavy engineering declines like 16 -- or 21% and 16% in the first 2 years, and it returns to the 7% of the field-wide decline. Again, we have not seen any decline as well. So at some point in time, we'll see some type of client. But we already know now that the management expectations of the PDP, which we reported earlier in this deck are more represented what we're seeing in the field. Netherlands Sewell acknowledge that, but they don't have enough time their engineering guidelines to make a change. So that's 1 of the things we're looking forward to this fall is truing up where Netherlands Sewell will come up where the field is performing.

That's correct. If you take a look at the far right column, the leverage metrics where we kind of where we stand today based on our reserve base is basically right in line with our long-term target of 1x net leverage. The beautiful thing of this asset and this cost structure is the ability to generate significant free cash flow. And so if you think about -- and we can flip to Slide 19, talking about our preliminary guidance for 26 through 28 this cost structure allows us to generate that free cash flow and potentially utilize that for deleveraging for shareholder returns. I think that management is comfortable with 1x net leverage long term.

On Slide 19, you can see our gross average daily production rates from 42.5% to 47.5% for the remainder of this year. growing to 55,000 to 60,000 barrels a day all the way up to 57.5% to 62.5% gross 1,000 barrels per day. These assets the LOE and the G&A costs are primarily -- roughly 80% fixed. So you can see the cost leverage that we have as we grow production. If we look down going from $20 to $22 per barrel on an LOE basis down to $9 to $11 a barrel in '27 and '28. So we look forward to achieving those cost synergies as we grow production. And as Jim mentioned, we'll be continuing to optimize everything on the -- our costs on the marketing front, I think that federal ability will allow us to do that and potentially achieve better pricing on that front. But the big thing and the big shift on this development plan is the focus on the low-hanging fruit going from potentially drilling wells in 2027 and '28 to focusing on these perf adds focusing on these low-cost E&Ps, which we have plenty of inventory of. It's very repeatable. And when we say we have a 50-plus year reserve life assets, as Jim mentioned, the barrels in place, the low-hanging fruit and the cost structure allows us to drive this strategy, drive significant free cash flow generation for a number of users. The income tax, we have -- we do have a sizable NOL that will be in place for a good period of time.

Let's roll to 20. We tried -- Slide 20, we've effectively modeled this out for everyone based on these -- on our cost structure here to get to an unlevered free cash flow unlevered free cash flow guidance for the following 3 years. You can -- if you take a look at the midpoint of our guidance range, $328 million for the remainder of '26, $753 million for 2027, $633 million. Now that's a significant amount of unlevered free cash flow relative to the debt that we hold on our balance sheet today. That's why we feel very confident in our refinancing strategy, like Jim mentioned, those efforts are led by JPMorgan we plan to access the debt capital markets here in June to handle our obligation on the '26.

Slide 21. This is our hedging and bonding strategy. We intend to hedge 100% of our expected PDP oil production volumes at least through 2028, what we've done in the past is we've implemented a combination of costless collars and deferred premium books or in any given year, any given year where you're actually exposed to the hedge, you have a costless collar. As we -- we buy deferred premium puts out for 3 years, right? And then you defer those costs by selling a call in advance of that coming production year. At any point in time, you're covered with a collar, but you're outside, years, call it, 2 and 3 are uncapped for pricing. So we can if prices rise, we get to enjoy that upside. But we have the fire insurance and the floor is in place, protect the free cash flows that we plan to generate.

We also have a $350 million on the bonding front, we've got a $350 million contractual P&A performance bond obligation due to Exxon at similar time to the maturity of the term loan. We plan to handle that obligation via the bonding surety market and/or letters of credit from our banks like JPMorgan. And you can see the various prices and hedging scenarios, this hedging the 100% of the in all of these cases basically protects the cash flow program, detect potential deleveraging of the ultimate debt that we hold on the balance sheet and it protects the shareholder return plan going forward.

Because of the constant production, the steady production, low-cost development, this is a 1 of the asset, the heads downside and we keep the optionality to the upside. We're very successful in this in 2003 to through the 2015 campaign with PXP, where we made a lot of money during that volatility and for our shareholders as well as protecting all the downside implement the same strategy. We have the same long-term reserve same production profile.

Slide 22 is a brief overview of this management team's history operating onshore and offshore California assets past primarily at claims exploration and production rolling into Freeport Makrand oil and gas back when California was -- had a different posture towards oil and gas operators. We actually won a number of awards out there Santa Barbara County specifically. And so I think we've demonstrated an ability to navigate the California regulatory and legal environment successfully, and we plan to do so going forward.

Slide 23, here our key investment highlights. As Jim laid out that the transition to the federal oversight has been paramount in getting our asset back on sales and prosecuting this significant strategic asset going forward. The Defense Production Act the interstate pipeline determination through PHMSA and then the federal offshore development permitting regime for not only drilling new wells, but permitting of the buy itself is very important. And frankly, it's why we purchased this asset because these assets fit in several waters, they don't sit in the state waters. The asset is prime for low-cost production growth as we outlined, the PFAD, the ESP installations, these are the low-hanging low-cost fruit that we can prosecute in the near term to drive free cash flow. And we can always adjust our plans based on prevailing commodity prices. We have a very large development inventory opportunity not only with PFAS but with ESPs as well. I believe right now, there are only 2 of the 92 producing wells that have ESPs installed like Jim mentioned, they may not be as necessary because the repressurization of the reservoir, and we've enjoyed that thus far, but they remain in the inventory and possibilities going forward in the long term. we have a, like you mentioned, plenty of drilling locations, over 100 drilling locations identified thus far and potentially more to come within that heavy oil window as well. We have a large production base, 47.5% to 52.5% estimated that 1,000 barrels a day net production 27 and 28. That consistent production profile, combined with our lowest cost structure allows us to generate that free cash flow and the optionality to delever and improve our equity story. We have a very shallow decline between 6% to 8%. I think that's where we are very differentiated amongst other E&Ps certainly in the Permian Basin and also in the Gulf of America. We have high operational control. We're 100% operated. We get 100% working interest in a high NRI of 83.6%. And that allows us to control our destiny and be flexible in various commodity environments. We have access to infrastructure and end markets we're selling -- we're currently selling our crude to Chevron at their El Segundo refinery in L.A., and we're also pursuing the federal buoy strategy in the event is necessary. We've touched on our HSD stewardship. We've done this in California. We've done it successfully. We know what we're doing. We know what we got ourselves into, and we've created a lot of value for all of our stakeholders in the past and a conservative financial policy. I think this asset certainly can support net leverage on a long-term basis. And I think we'll use that on -- in the long term on this 50-plus year asset to drive the shareholder returns like we mentioned.

That concludes our presentation. Harrison, I'll turn it back over to you for any questions.

Yes. So at this point, we'll take Q&A from certain analysts, I see the queues begun, and we'll start with Lloyd Byrne at Jefferies.

[Operator Instructions] Our first question comes from Lloyd Byrne at Jefferies.

Great. Jim, Greg, Harrison, thanks for the presentation and all this information is great. Can you just start with the maintenance capital? And how far out do you think you can take that? I think you talked about 4 years, Greg. And just what's the probability that you will or won't need ESGs and then any costs that would come with that going?

As far as the capital, for 27, 28, I think we forecasted $80 million total company-wide. That includes facility -- additional facility upgrades, some instrumentation these are 50-year old facilities that are fantastic, but there's a lot of modernization going on all the time and especially in some of the full exploitation strategies. Of that, we're talking about spending $10 million to $15 million on perf adds -- sorry, F&D cost is super low. But if you just include all the capital, Lloyd, it's about $4 a barrel F&D cost with all capital. We just for drilling completion capital, it's about $0.64. So that you can kind of map it out there. And as that capital where the capital would ramp after 29 is when we thought about drilling rigs out there starting according to our plan that works pretty well as far as generate the free cash flow and so forth. And if you look at it from a debt extinguishment model, which is part for sales worse I've always refinanced more than extinguished, but from a debt extinguishment that model, then you've got a lot more operating margins to put capital work and with the drill bit, and we probably moved 2 drill rigs out to larger platforms and start growing production from 29% to 35%. That's the current model. We can accelerate that at any point in time we refinance this debt and covenants or whatever we're in a position with enough free cash flow to put a rig out there, we can always move that forward along those lines. So ESPs focusing on them, they're flexible, wherever we feel like we need to support production based on the well performance. We're able to do that. We have plenty of pipeline capacity. We have plenty of electricity capacity we run ESPs in the field to the West that we operate points way up very successfully. And -- but it's usually when you have a higher water cut wells and lower pressures. Our wells, obviously, with the repressurization, came on a much higher oil cut than we thought, which is great news and much higher prices. So our gas lift operation is working spectacularly lifting those volumes. And as -- we'll just see how the field sells out. No one's ever done this before, so in oil till them for 10 years and then put it back on production. There's no lot on it. And so the Netherland Sewell engineers and our engineers are learning as we go, but we're learning from a very positive plate. Does that cover everything?

Yes. Yes, that's very helpful. I have -- let me ask -- I have 1 more quick one, and then I have another one, if I could. Just the hedge, how far out duration-wise, do you think you would be willing to go? I mean, the back end of the curve has come up even if maybe the as high as people think in the market, should the back ends come up a bit? Just how far would you go out...

We haven't made a final decision on that, but my favorite deal is to about 2 to 3 years of floors and then say, floors at $70. I'm just from a staff line. I said it cost $5. And then what we'd sell is 6 months to 12 months ahead, calls to pay whatever the $5 call would be to cover the cost, make it cost us collar, but we roll into that. When we did this in 2003 to 2009 at PXP is very successful. We had a $25 -- we've put so for a $25 a barrel, $50 a barrel, $100 a barrel, $1.25, and we'll get ready to sell lots more puts at $150 a barrel. You remember oil cap at 14,750 and then it dropped down to $27.50 at Valentine's Day in 2009. When we closed out all of those floors, and we had about $25 a barrel of premiums, both all those cores, we harvested $1.1 billion of that hedging market, and we paid off $800 million of debt. So that -- having those floors are the key and Gregory and his team have been very good at optimistically thinking about where to sell the calls to maximize our price opportunity, but also a standpoint, cover the call. So it's an ongoing live exercise that we've managed very well in the past, and we're excited about -- and the key is you have to have low decline, reputable production and repeat and that's why this plan works so well operationally with that financial plan.

That makes a lot of sense. Sorry, if I have 1 more. Just it's my understanding that DOE and the DOI of field trip later this week got the lost florists. And just wondering if there's anything you can comment on there here is that how to do with the buy strategies that have to do with financing, something else? I'm not sure you want to comment or can, but I know it's out there.

No, it's not -- and also, there's also DOTs coming as well. All 3 secretaries right now are scheduled. Risberg and Duffy are all coming out there and so forth, a massive amount of people, 37 folks. I'm glad we have a big facility to handle them all. But we don't really qualify it. We found out to the federal government as a hardship financial case because of all the free cash flow. The models are -- so the financial support is probably not as realistic as anything we talk about. But the regulatory support and the operations for has been phenomenal, obviously, with the DPA and so forth. And there's -- we're discussing several condemnation strategies with all 3 groups and stuff like that and trying to come to a strategy that everybody likes because the federal government has been 100% supportive of us, interstate pipelines, DPI, they're committed and adjusted farm is shown strong efforts as well committed to ensuring our operations are lawful and safe and able to get done. So we're excited about having them all out there. And if anything comes up, and I'm sure we'll be on post who you guys can read about.

Your next question comes from Michael Ferro from Pickering Energy Partners.

I appreciate you guys hosting this call, providing all the color and thanks for having us on. I'd just like to hit on the perforation adds. I mean the initial results look great and are clearly highly capital efficient and maybe even seem to be a driver of the strategy change. We were hoping to hear more about the repeatability I know the company is probably not expecting that every project is going to add 1,000 barrels a day, but there seems to have been something that the Sable operating team noticed on these first 2 purposes that gave you the confidence to the go-forward plan. So maybe could you elaborate on what you saw in these first 2 projects and maybe speak on how repeatable you think those characteristics are for the remaining prospects?

Yes. So if you look on Page 11, as a reference point, the type log on the right-hand side of the page, and it's got the existing person in the massive chart in red and it's got the plant person yellow, what you always worry about in these things is they're in communication, even though the 400 or 600 feet of pay and the upper solicitors hasn't been perforated in the field, you always worry about whether there's communication between the reservoirs, and that shale breaking between is obviously the key integrity point. So if I haven't -- so now that we've tested to them and realize that Shales tremendous integrity and that the need drained upper colitis is not communicating with the massive chart. That's what gave us -- that allowed us to say, the confidence that this is something we can put our operational plan on. So we're very excited about it. We have 600 feet of pay in a virgin reservoir basically in upper solicited just a few wells drilled on in different parts of the 77,000 acres. So it's a brand-new oilfield sitting up on top of the massive chart, and we produce 650 million barrels. So I've never seen this before in my life. So the aspect of this opportunity is once in a lifetime to have this kind of all in ore recovery for those perforations. Now that we had 2 of them on production and they haven't declined and the like branding wells, it's coming on, it's a spectacle opportunity for all the stakeholders to Sable.

Great. Appreciate that color. Just a follow-up on the strategy change. I mean it looks more like a maintenance mode now that's focusing on maximizing free cash flow and even potentially reducing some debt. I know the company has previously mentioned the opportunity for shareholder returns. So under this new strategy, could you maybe speak about how your capital allocation priorities change, if at all?

Yes. The shareholder returns are obviously we're all shareholders, and we're very focused on that. And what we want to focus on getting the business refinance and getting it fully owned production here this year with all 3 platforms and have our new reserve report come out at the end of beginning of '27, at year-end '26, with no restrictions, no problems or that type of thing. We're all -- we know exactly where we are in the investment and where we are and so forth. And then we can look at our debt structure, hopefully pays to debt down by the end, we may look for some permanent capital the bond market, that type of thing beyond this term note, and then that would give us an opportunity to kick off our shareholder return program. But we're adamant about doing that as soon as possible, especially if we unlock the free cash flow from a long-term structural debt perspective, and we're able to turn that money to our shareholders in dividends or stock buybacks. Greg, do you want to add anything?

Yes. I think the key there is we've got the underlying free cash flow profile to handle both and we've got the reserve life to not only continue the shareholder -- prosecute a shareholder return plan, but to do it over decades versus some short-term 5-year program. We plan -- we judge we're all focused on that. Like Jim mentioned, we're all shareholders, and we're going to drive that. And the good thing is we've got the asset, the cost structure and the reserves in place to do it.

Your next question comes from Charles Meade, Johnson Rice.

It seems you guys will talk a little bit more about your refi process. And I recognize it's in process, you might be appropriately sensitive out of it. You guys seem pretty confident. But for equity investors from the outside looking in, looking at 3 weeks to maturities is we'll close shave the equity investors are used to. So maybe as a -- maybe that 1 thread to pull on here is you guys have is on Slide 18, of where you talked about a May 31, 2026 reserve performance. So is this the kind of thing that you're just now getting in front of your banks and that's why the -- that's why we haven't heard anything yet. So -- and so it's going to be a busy 3 weeks or alternatively, is this kind of thing where your brands have been looking at your reserve report, and this is just a kind of pro forma roll forward to May 31. Whatever the next couple of weeks look like?

Yes. Yes, Charles. We've been getting just to time information on the reserve report, but also production history and so forth, make sure that we feel like we support everything. And every day, we feel more confident, okay? And so the aspect I wish we had 180 days of production, reserve report that all of PDNP would be PDP and so forth. We just ran out of time. So we pushed as far as we possibly could. Every 1 guy called me said, you waited for Iran to kill negotiations to start the deal said, no, we had no coverage on that. So it's just the way the timing worked out. There's a lot of moving parts here, but we're confident with our bank, JPMorgan and the group they have together for us being able to execute on this plan with plenty of time to spare.

Yes. Charles, to answer your question. I can assure you, we're not just now getting in front of the banks we've had JPMorgan engage as lead on our refinancing for some time now over a year. And I'll also tell you, we have left no stone unturned in terms of federal credit support options. But like Jim mentioned, based on the free cash flow that we're going to generate the reserves and the commercial finance ability of this asset, we don't qualify as a hardship case for the Fed. I'd say some of those -- from those discussions are ongoing, but we don't plan for them to be there to handle our maturity here in June.

They've matured into operational support versus financials.

Correct.

Got it. That's helpful detail. And then, Jim, can I can go back to this -- the added birth in the upper species. I think you said a couple that there were maybe 7 million I think you have a lot of penetration, be manly 7 per intervals in that, that were -- I wonder if you could just talk about the history of that. I mean, because it looks pretty similar on the laws and you guys talk about having a kind of almost 4x from on your the that historic from the solutions or from the churn and tested earlier expect?

Remember, Exxon was rolling out their plan and they got interrupted by the Wolseley. If Exxon had 5 years, they roll through all this stuff, okay? But they got interrupted by the Wolsfeld shut down. And so it just kind of -- it's like finding a far and someone basically just bought the house. I mean it's just sitting there and going to look at this. And so we're just picking up the baton from there. This isn't like hidden camera flash or whatever, just haven't got to it yet. They only have about a dozen perforations in the 77,000 acres. You've got hundreds of millions of barrels in this upper solutions that we're just going to harvest fashion way with existing wells and per at. Like I said, this is a once a lifetime opportunity we've ever had situation like this before. And I'd be surprised unless you have some major dislocation like an oil spill offshore California or find some Middle East deal that's been under conflict for 20 years, that can be reperf, that type of thing. So it's got -- it's a very unique situation, and we're happy to take advantage of for all our stakeholders.

Your next question comes from Leo Mariani from ROTH Capital.

Yes. Just wanted to follow up really quickly on the debt refi. You spoke about it a little bit, but if I heard you guys correctly, it sounds like you're pretty confident that kind of a straight debt solution and we'll be able to take care of this at this point in time. And it sounds like you're suggesting this is sort of a bridge type financing with me some kind of term loan. And just to clarify, it also sounds like at this point, it's just given the cash flow profile that federal and credit support seems pretty unlikely. I just wanted to clarify those things.

Yes. Leo, I'd say you're right on the Federal Credit support at this time. I think we are pursuing best capital markets for this refinancing, and those efforts are led by JPMorgan.

Okay. And I just wanted to follow up on the buoy. Obviously, you talked about needing some regulatory sign off for this oil buoy here. Just looking at your kind of marketing situation, it looks like the oil price realizations, maybe for the rest of the year seem a little bit lower than I think I had expected here. Do you see that this buoy will really kind of improve that? And any comments on like what capacity might be on that buoy? And could this kind of dramatically change your price realizations going forward? And then just apart from that, is there any opportunity maybe in the next call it, year improved realizations regardless of net, which I know it's going to take some more years to put in place.

Yes. The marketing optionality will give us a better leverage. The world would be our refinery market versus just California. And obviously, with the shrinkage of the refining market, the refiners have the upper hand as far as pricing and so forth. The capacity on the boot would be up to 150,000 barrels a day. We had a 24-inch pipeline going back and forth, we'll have pumps for that at max capacity from a sales standpoint, just matching our capacity, we have the loss Voice Canyon. And so from our standpoint, it's another outlay, but it's a big part of our condemnation strategy with some of the state of California issues that I hope to be talking about later this month. once we get some clarity from the federal government in which direction we all want to go. So they're very helpful there, and that's really, really important strategies there and the boys part of that as well. So we're well coordinated with them. We just want to put a conservative timing on that from a standpoint of of going through the process, but it will be done, obviously, during the existing administration of Donald Trump.

Okay. That's super helpful. And then just last 1 for me on production. I heard you right earlier, Jim, you talked about around 46,000 gross barrels a day, I guess, as of today. sounds like a pretty good number, just kind of relative to your guide just given that your final platform isn't on yet for the year. So it seems like you're in good shape with respect to the guidance that I heard you right on that.

Yes. And Leo also on that too, we got notification by BESI in late last week -- or last week about being able to debottleneck some of our gas production. And I realize we have gas compressors for gas lift, the lift of oil on the visual platform. We're sending gas to shore. So we can displace the electricity. We're having to buy on the grid with our own cogen, our own gas-fired electrical power plant. So we're still debottlenecking some of that. So this is a uplift that 46,000 barrels a number once we get all the wells on and pairs and harmony that some of have been restricted just because we haven't got enough gas to be able to handle the gas they make or do have enough compressor gas to allow to activate the uplift on those. So there's still more unwinding to do on Harman heritage. We're really excited about seeing the perfect at Hondo mid-summer and see how they come on.

Your next question comes from Noel Parks from Tumi Brothers Investment Research.

I was interested in the heavy oil potential that you identified in the slide. And just wondering if you could talk a bit about if that were successful, what the processing and marketing might look like? I know you touched on it a bit, but just interested to be hearing more about that.

Yes. Exxon has drilled 2 wells and complete and produce out of the heavy oil. Have you had a lot of solids whether it takes a different processing at the surface. And so it was -- they are picking up, we're going to have to upgrade some of our separators and don't handle the heavy and the solids and some of the spring and so forth. It's not really compatible to produce it with existing processing facilities we have with the massive chart and uplift. That's just money in engineering. It's not a big deal. But what's amazing about the heavy oil standpoint but 139 to 13 grams or the Exxon produced it's very viscous and they'll flow fantastic productivity just like all the other wells. So from that standpoint, haven't appreciate. And we haven't seen the down dip or limit heavy oil leg. And that's why right now, we've proved up over 500 million to 600 million barrels on the structure. But there's -- we're not -- we haven't got to the bottom of it. We don't know how much there is, you can then that there could be as much as 1 billion barrels additional of heavy oil that we could add to our observes. So let's talk about taking the heavy all out and producing it. We would end up having a sidetrack existing wellbores, we drilled existing or new wells for the heavy oil portion because of the prolific production on upper solicitous and massive chart. It's going to be a blending of the heavy oil with our existing oil production over the next 30, 40 years. As far as when we get into stripping heavy oil and all the upper solicits a massive charter depleted. So it's going to be able to be mixed in if while for us to get all our facilities tuned to where we can do all both phases of this oil environment to do at the same point in time, we're added about it, and we're super excited to have that reserve in our backpack and just see how that unfolds. You can see us delineating the heavy oil reservoir in the next couple of years and coming back with more reserves because of our ability to -- when we drill some of the wells we get a rig out there. to drill to some extent, longer deeper wells to figure out whether that all a extends. But that's a 100% upside to our testing.

Great. And I was wondering when you talked about the repressurization putting off the need for ESPs, does the refresh position alone explain the upside versus your expectations that you've seen in production so far with let's come online? Or are there other factors in the mix as well?

Yes, it is for a couple of reasons because remember, Netherland Sewell gave us 34,000 barrels a day gross out of 3 platforms. We're trying to feel back on. They just put an arbitrary 30% discount for unknown reasons and so forth, the public engineering discount. So now we're looking at forecasting somewhere upwards of 60,000 barrels a day with platform of Hondo on, 55,000 to 60,000 barrels a day. That's all repressurization and reestablishment of the hydro dynamics of the reservoir. One of the key things we've seen, just like the engineering book side, we've seen gas move back into liquid back in the solution based on repressurization, we've had wells in our up-dip position in the gas cap that we're producing 15-mile cubic feet of gas a day are now producing 1,500 barrels of oil in no gas because the gas cap has shrunk back into the oil in solution. So there's some heavy-duty engineering things that are great textbook going on in this repressurization, and they're all positive if you're looking for oil production and liquid production. So far, so good.

Your final question comes from Subhasish Chandra with StoneX.

Jim, in the past, you kind of had a dividend per share target. Just curious if you're thinking of the world the same way.

Yes. Yes, we are, Subhasish. Just timing that we talked about earlier. Once we get Exxon finance out, obviously, those dividends are prohibited under that term loan and so forth. And once we get understand the terms of the new financing. And then I'd like to push toward look at spring next year once we have some permanent financing in our full-fledged reserve report and we get the full value of what we've created out here in this company to recognize that we could establish that as soon as probably.

Okay. Got it. And I think previously, you talked about $4 per share. Is that still sort of the number you had in mind?

That's under pressure because of our share count and that share offering we had to do in the fourth quarter last year that we got sideways with. So we'll have to address those issues once we get the cash flow. We certainly have the capacity to also functional oil price as well. What's the oil price at. So that's -- we can back into what our free cash flow is and what our capacity will be.

Right. And also potential repurchases of shares versus dividends, right? So that would be a debate, the management and the Board on how we prosecute that shareholder return strategy going forward.

Got it. And could you remind me, I think the gas handling capacity, at least nominally was about 80 million cubic feet per day, something like that. Like where are you -- you addressed that a little bit kind of where are you with regards to your gas capacity?

Yes. Just breaking that this way. We have gas needs in the field for our gas lift operations. We got also we're sending gas to shore to run our electric cogens and so forth. Then we have ability to sell gas once our Paco plant is fully up to speed now it will be fourth quarter this year, where Paco will be fully repaired and be able to start selling gas. So somewhere between 80 million and 90 million a day on a sales basis. But I got to take you right now, a lot of those gas wells are produced in oil. We don't have that much gas to sell. So it's going to be more over time as the field normalizes out and the gas production comes up, we will be selling more ore than we will gas. So I would cut that in half in the 40 to 50 range on the gas sales for next year, might be in a better position to be in. Hopefully, we're surprised because we have so much all that we don't care about how much gas we sell, but if not, we have more gas, we'll start to sell up to 80 million, 90 million today.

Okay. Yes, that's good. Yes. And my final question, just seguing into that. So you're not seeing any gas cap yet. So on the perps, you're not seeing higher gas concentrations. Do you think that -- I mean, so far, the evidence is you're not seeing it, what do you think going forward? Do you expect a higher gas cut as you on the perfs?

Well, 2 things, oil field is depleted. We will see some depletion. We will see some pressure on the client. We will see some gas production increase as the gas breaks out a solution. The question is when. Is that this year, next year, 3 years from now, 4 years now, whatever it is. And just so far, we've been pre surprised in the last 90 days that we -- there's no visible decline in the field. And as we add more gas lift, we're seeing the production response. So this has been a beautiful restart, and we're going to write it as long as long as it comes out, we'll just be updating people. And we're ready to fill the ESPs in just to maintain production at a low cost to keep our cash flow maximum. And then we got a lot more than 8 to do over time, depending on what the field does. So this is just the beginning of a long, long novel of opportunities and harvest the field most cash flow maximizing strategy possible.

This completes the allotted time for questions. I will now turn the call over to Jim Flores for any closing remarks.

Great, operator. Thank you very much. We've certainly enjoyed putting this presentation together and be able to announce all our stakeholders to what the value has been created here at Sable Offshore and we really appreciate the financial -- I mean, the federal government support of all our operations and prioritize this project under the National Energy Dominance Council as far as 1 of the key projects by our federal government support. And we're going to continue to maximize that for all the stable shareholders and like in our condemnation strategy, you'll hear more about in the coming weeks and all the progress we're making with the Justice Department in the courts. So thank you all, and we look forward to seeing you soon. Bye.