Hello, and welcome to the Sable Offshore Corp Investor update call. We ask that you please hold all questions until the completion of the formal remarks, at which time you will be given instructions for the question- and- answer session. 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. Roll to the next slide, please. The disclaimer, everybody can read that at their leisure. It's for everyone's protection. On to slide three, which is the introduction to Sable Offshore Corp. This today will be our most comprehensive report on Sable. We've owned SYU 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. The backbone of our company is the 15.5 billion barrels in place, and extracting over 2 billion barrels recoverable with about 1.5 million barrels of total remaining reserves. 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 in position to do that. We create a lot of value with SYU on the PV-10 strip of about $6 billion. Exxon developed the field and built everything there. We bought it a few years ago to take it and put it in our Flame Acquisition Corp. SPAC, and later Sable Offshore Corp. 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, the Defense Production Act, that was ordered by the President of the United States. Our platforms, Harmony and Heritage, began flowing in May of 2025 at very low rates just to make sure that we started to get all the equipment working because we weren't able to sell. We were continuing to bank oil in the 540,000-barrel tanks in 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 just two of the three platforms is around 46,000 barrels a day. Sable is currently pursuing refinance for the Exxon term loan, which is scheduled to mature on June 26, 2026. Our bank, JP Morgan, is spearheading those efforts. Page four, please. The history of SYU began with Platform Hondo, with a single platform and an offshore treating and processing vessel called OS&T that was barging oil out and so forth, and made 160 million barrels. In the late 1980s, early 1990s, they were able to expand the operating footprint with Las Flores Canyon, with all the processing being brought onshore, then also the installation of Platform Harmony and Platform Heritage and associated pipelines, as well as the Santa Ynez Pipeline System that goes back to Pentland for sales. That allowed the field to dramatically increase production to about 115,000 barrels a day. As fate would have it, instead of supplying the California offshore market, here came the North Slope of Alaska in the 1980s and basically became the overwhelming fuel for the West Coast. The development of SYU was idled by Exxon until after the Obama administration lifted the export ban in 2010. In 2012 and 2013 and 2014, started drilling some wells, and just about when we got about five wells drilled, the Plains Pipeline, which is now our Santa Ynez Pipeline System, had a rupture and was shut in for 10 years. We've reestablished the production on that and are going to move back to the full field-wide development of SYU going forward, you'll see. On page five is assets. The lease is in yellow. That's our unit. It's one single unit called the Santa Ynez Unit. We work in conjunction with the Bureau of Ocean Energy Management, what is BOEM and BSEE under the Department of the Interior, all federal waters. You see the state waters are in light blue where our pipelines cross through our Las Flores Canyon, and then the Santa Ynez Pipeline System continues all the way back to Pentland and then on to the Los Angeles refineries. The Santa Ynez Pipeline System now begins at Platform Harmony in federal waters and goes through the state waters and onto the state, and therefore it's designated an interstate pipeline by the Department of Transportation and their PHMSA group that has jurisdiction over it. The total federal leases are 76,000 acres, and currently we're selling oil 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've moved the processing offshore and then try to offload one of the international cargoes into the international maritime market. We've since refined that plan. Instead of having an expensive offshore facility, 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 crude into Las Flores Canyon for processing. We'll export it out of Las Flores Canyon instead of in the existing Santa Ynez Pipeline System or the extension of the Santa Ynez Pipeline System out through Platform Harmony for sales in a traditional buoy like they have down at Long Beach and El Segundo. It's 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 for the pipeline, and about $25 million worth of pipe valves at Platform Harmony for the modification. For $125 million, we have a secondary outlet besides our existing SIF pipeline in case anything happens, either operational or regulatory, or the refinery market continues to collapse in California and doesn't 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 BOEM and BSEE. We've been discussing with them. We've got to work through all those processes. I would say also, EPA as far as air permit. There's no net increase in that other than the tankers coming and going like they are in Long Beach because we're using the same process. It's a low carbon, a low emissions strategy of choice for us. Of course, we'll need Department of Commerce to oversee some of the regulatory obstacles that California will try to put up. We're very familiar with all three of those outlets, and we work hand in hand with them, and we look forward to pursuing this buoy. It's a very significant part of our strategy to de-risking whatever might happen regulatory-wise from California. Back to the asset on page six. We wanted to rank SYU as far as all the major fields in the Gulf of Mexico and of course, West Coast and so forth. We ranked number four of cumulative production, also remaining reserves to get out of the ground. This just shows you where we rank at some of the biggest fields of the world. From my career, some of the East Bay fields and Main Pass 69 fields didn't even make this list, and they were some of the biggest fields I'd ever seen. This is obviously the largest project I've ever dealt with as far as remaining reserves that we're looking forward to taking advantage of. Next slide, page seven. With a 77,000-acre reservoir and multi-tiered 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. That's what we're going with right now is 2.2 billion barrels. It's produced 671 million barrels a day. Total remaining reserves is 1.5 million barrels. Our primary forecast of 894 million barrels is basically in the known field plays in the Upper Siliceous and the Massive Chert. We have the heavy oil forecast. This is below 13 gravity oil. Exxon, our predecessors, drilled a couple wells. The oil is viscous. It flows. We just don't know how far down the reservoir goes. As far as has been tested, we've established 618 million barrels of recoverable oil, 13 gravity oil, it could become much larger, and that would push our total ultimate recovery closer to 20%. That's going to be a big part of our identifiable efforts of value going forward. It will take some upgrades in some of our processing because the heavy oil takes a lot more separation and so forth to process. That's on the horizon beyond our remaining forecast that we have right now in the primary. On page eight is really an update slide. I'll remind everybody about our SIFS pipeline and our processing facility at Las Flores Canyon. It's all been hydro-tested to much higher pressures than operating pressures. It's fully hydro-tested, and remember that our total max capacity is 150,000 barrels a day. We have plenty of capacity if we want to add another platform out to the east so we can get some more reserves beyond the three platforms we have. Right now, with production ramping up since May of 2025, we have 22,000 barrels a day out of Platform Harmony and about 30,000 barrels a day out of Heritage, a little higher than that today with the 46,000 barrels a day we produced. We're producing now, our platform, Hondo, has gone under extensive renovation. This is a 50-year-old platform. We've done some structural work. We've done full instrumentation and so forth. It's scheduled to be on by mid-summer, we're doing several of our initial perf adds at Hondo. I think it's nine of them there, they've been coming in at 800 to 1,000 barrels a day. It's really enhanced the production there. We expect another 15,000 barrels a day or 10,000 to 15,000 barrels a day out of Hondo, and when we get the full production by early fall. Page nine is our development plan. This plan was to maximize free cash flow, the best way to do that is minimize our spending. As you can see, we start off with 129.4 million barrels at the end of 2025, beginning of 2026. This plan fully replaces all the barrels that we produce over the next four years through perf adds, which are basically dropping tubing guns down the tubing and shooting additional perforations in un-perfed zones in the existing reservoirs, very minimal and so forth, very low cost. The average across the four years is $0.64 a barrel replacement cost. You can generate a lot of cash flow when you only have to spend $0.64 a barrel to replace all the reserves. These are basically moving PDNP reserves to PDP. We're just talking about our PDP reserves. From a credit standpoint, having the same number of barrels four years from now we have today with spending this minimal amount of dollars is a spectacular position. It's the same thing we did onshore at PXP for 15 years, where our reserves didn't change for 15 years. We made sure we maintained our reserves through the same type of activity. It wasn't perf adds, but it was steam optimization in that case. This case is straightforward. We've actually flip the page to next page. Page 10, we've actually conducted two of these operations. You can see on here, Sable's, the third bullet, there were 250-280 barrels a day respectively. Now they're 900-1,100 barrels a day respectively. These are spectacular intervals to shoot. It's just left behind pay that wasn't harvested because it was too premature in the field's life when Exxon had it when we produced it in prior to 2015. You can see how it rolls off with our perf inventory of 56 remaining perf adds. We have two already done. We'll do nine more in 2026, and then we'll do 10 more in 2027, seven more in 2028, and 15 more in 2029, and with 15 more remaining after that. There's also, in 2028, we're talking about adding eight ESP pumps. As you'll recall, in the IPO, that was one of our initial strategies that we thought we'd have to institute immediately. The pressure in the field has come up at about 25%-26% from where it was when it was shut in based on just geologic forces like water drive in this big reservoir. With the pressures in the field, we've had no immediate rush to go out there and try to assist flow rates with the ESPs. 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 get some benefit of adding additional pump capacity out there, and that's what we have for ESPs. If it doesn't happen until 2029, it'll just push the ESPs back. If it happens earlier and we need to support our production and our reserve replacement, we'll move them forward to 2027. That's our safety valve to make sure we hit our plan on the previous page nine, with eight ESPs in our pocket, plus a remaining inventory of 15 perf adds to add to it before we put a drilling rig out there. Each one of these perf adds and each one of these ESPs add 1.25 million barrels net to the PDP line of the company. It's very, very important. The illustration on page 11 is our cross-section. You'll see the existing perfs in red. They're in the Massive Chert and right at the top of the Lower Calcareous and so forth. The Upper Siliceous zone has had very few wells in it. It's very lightly tested across the 77,000 acres, it's very prolific. We're going back and adding perforations to the existing perforations. We're adding those in the Upper Siliceous. Those are the cheap 56 perf adds that we're talking about, and maybe a couple in the Massive Chert where they perforated low in the section. This is just oil field 101 and basically a big, large production field management. The heavy oil upside, we'll be drilling sidetracks at some point in time and drilling out to produce that as well once we do the facility modifications that are able to handle the heavy oil. It's a tremendous part of our story going forward for years and decades ahead. The long-term opportunity, this is our initial Upper Siliceous drilling, the 100 wellbores here. We have multiple additional locations in the Massive Chert. Of course, the heavy oil leg will cause basically redrilling of the field from a proved basis. We have a lot of drilling to do that's 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 Brent. 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 that you get more PDP reserves, the field life by keeping the LOEs lower because of the production volumes and so forth. You can see how we'll play that in the value we're going to create going forward. This is a very low-risk plan. It's all within our platform, our rigs, and so forth. 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 governed on our export pipeline in SYPS by the federal consent decree, which was the settlement and 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 required certain aspects of prepare work to be done for the pipeline and hydrotesting and so forth before the operator can restart. We inherited this consent decree. We've implemented all the repairs. We did almost 200 digs and repairs with Office of the State Fire Marshal, the governing body for California's personnel standby with us. We worked with them on the report to the Head Fire Marshal that's in Sacramento and so forth of accomplishing everything. At the same point in time, we dual-tracked this to PHMSA because of the addition of the federal pipeline offshore with our state pipeline. We thought 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 and that they independently reviewed and so forth, and gave us approval to go forward as an interstate pipeline under PHMSA jurisdiction, and so forth. Basically from there, the Department of Justice, who's the enforcer of the consent decree, has deemed we're complete with 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 8th. We're optimistic that at some point in time that justice will prevail and get that dissolved. The aspect is it doesn't apply to us now from the PHMSA ruling and also the DOT and also, of course, the Defense Production Act that become an interstate pipeline allowed the President of the United States to order the Secretary of Energy to declare a Defense Production Act to immediately start producing oil at maximum rates through the SIPS pipeline system. We did that about 75 days ago. That all rolls up into page 15. This is current. What's happening now is obviously California's had some heartburn over our federal decrees and Federal Defense Production Act, and the Department of Justice, our legal group here at Sable as well as our outside counsel, have been working hand in hand toward clearing that up and getting that straightened out. We continue to have good results there as the federal law applies, supremacy law is very effective here as far as realizing that the federal government has preemptive rights over the state. Moving on from there, from page 15 to page 16, the milestones we've achieved is we completed the repairs to the SIPS pipeline May of 2025. We restart production at Platform Harmony in May of 2025. Complete successful hydrotests of SIPS in 2025. Those hydrotests are key because you put it under immense pressure beyond operating levels, you make sure the pipeline has got 100% integrity, which ours do. Resume oil transportation through SIPS to the LFC Midstream processing facility in May of 2025, where we're banking the crude and our tanks ready for the journey back to Pentland so we can start selling it. The federal regulatory oversight in SIPS. I talked about getting the SIPS pipeline confirmed as interstate pipeline December of 2025. Defense Production Act March of 2026. Resumed petroleum transportation through segments 324 and 325 of SIPS in March of 2026 back to Pentland, which is our sales point back to south of Bakersfield. First sales to Chevron in SIPS March of 2026. I think I had one day of sales in March, right, Gregory? That's two days. It was significant around here. It was our first sales in five years. We had restart production Platform Harmony April 2026. That's where we are today, we want to have as much production history as possible before we want to go out to the market and be able to communicate to all our potential stakeholders about the refinance of the Exxon note. Refinance of the senior debt expected here in June. Commence commodity hedging program June 2026. Restart production at Platform Hondo, that'd be third quarter 2026. That's the platform we're having to really refurbish, also has the nine perf heads that are a big part of our production. Potentially install the oil sales buoy at Santa Ynez Unit. We have some federal regulatory hurdles we must hit. That's why we put potentially, but that's a big part of our process on the buoy because it'll give us a secondary outlet, so sale 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. Continue legal protects Sable's best interests to pursue all monetary damages. We have about $450 million worth of lawsuits against Coastal Commission and 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'll turn it over at this point in time to Gregory Patrinely, our CFO, to do the financial overview of the current capitalization on page 18, Gregory. Sure. Thanks, Jim. On slide 18, this is our current cap table. As Jim laid out, the massive reserve base that we have and the low cost structure, including the unheard of finding and development cost to maintain flat PDP, that all leads to very robust asset coverage. If you take a look at our PDP, the net reserve coverage columns here, 2.6 times on net debt on PDP alone, 5.8 times on approved basis, 1P and then a first 3P estimate of 6.7 times. Just backing up on the reserve report itself, we plan to have a full 3P Netherland, Sewell reserve report at year-end with the filing, in conjunction with the filing of our 10-K in 2027. We look forward to continuing to work with Netherland, Sewell on that front. Today, we also posted our preliminary Netherland, Sewell approved report. 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 Hondo is not online yet. We fully expect those wells and those reserves to be PDP, which is what's reflected in this table. Yeah. One comment about that report, there's not enough production history on the wells to be fully un-risked by Netherland, Sewell. They still have heavy engineering declines, like 21% and 16% in the first two years, then it returns to the 7% of the field-wide decline. Again, we have not seen any decline in these wells. At some point in time, we'll see some type of decline, but we already know now that the management expectations of the PDP, which we reported earlier in this deck, are more representative of what we're seeing in the field. Netherland, Sewell acknowledges that, but they don't have enough time under their engineering guidelines to make a change. That's one of the things we're looking forward to this fall, is truing up where Netherland, Sewell will come up where the field's performing. That's correct. If you take a look at the far right column, the leverage metrics, where do we stand today based on our reserve basis, basically right in line with our long-term target of one times net leverage. The beautiful thing of this asset and this cost structure is the ability to generate significant free cash flow. If you think about, and we can flip the slide 19, talking about our preliminary guidance for 2026 through 2028. This cost structure allows us to generate that free cash flow and potentially utilize that for de-leveraging for shareholder returns. I think that management is comfortable with one times net leverage long-term. On slide 19, you can see our gross average daily production rates from 42.5-47.5 for the remainder of this year, growing to 55,000-60,000 barrels a day, all the way up to 57.5-62.5 gross thousand barrels per day. These assets, the LOE and the G&A costs are roughly 80% fixed. You can see the cost leverage that we have as we grow production. If you look down, going from $20-$22 per barrel on an LOE basis, down to $9-$11 a barrel in 2027 and 2028. We look forward to achieving those cost synergies as we grow production. As Jim mentioned, we'll be continuing to optimize everything on our costs on the marketing front. I think that federal buoy will allow us to do that and potentially achieve better pricing on that front. 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 2028 to focusing on these perf ads, 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 asset, 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 uses. The income tax, we do have a sizable NOL that will be in place for a good period of time. Let's roll to 20. We've effectively modeled this out for everyone based on our cost structure here to get to an unlevered free cash flow guidance for the following three years. If you take a look at the midpoints of our guidance range, $328.9 for the remainder of 2026, $753 for 2027, $633. 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 JP Morgan. We plan to access the debt capital markets here in June to handle our obligation on the 2026. 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 puts. Where in any given year where you're actually exposed to the hedge, you have a costless collar. You buy deferred premium puts out for three years, right? 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 your outside, your years call it two and three, are uncapped for pricing. If prices rise, we get to enjoy that upside. We have the fire insurance and the floors in place to 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 a 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 JP Morgan. You can see the various prices of the hedging scenarios. Hedging the 100% of the PDP in all of these cases basically protects the cash flow program, protects 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, the low cost of development, this is a wonderful asset to hedge the downside and keep the optionality to the upside. We're very successful in this from 2003 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 downsides. We 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 in the past, primarily at Plains Exploration & Production, rolling into Freeport-McMoRan Oil & Gas. Back when California had a different posture towards oil and gas operators, we actually won a number of awards out there within Santa Barbara County, specifically. 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 are our key investment highlights. As Jim laid out, 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, then the federal offshore development permitting regime for not only drilling new wells, but permitting of the buoy itself is very important. Frankly, it's why we purchased this asset, because these assets sit in federal waters, they don't sit in state waters. The asset is primed for low-cost production growth. As we outlined, the perf adds, the ESP installations, these are the low-hanging, low-cost fruit that we can prosecute in the near term to drive free cash flow. We can always adjust our plans based on prevailing commodity prices. We have a very large development inventory opportunity, not only with perf adds, but with ESPs as well. I believe right now there are only two 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, like Jim 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, 47.5-52.5 estimated, that 1,000 barrels a day net production in 2027 and 2028. That consistent production profile, combined with our low 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%-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 Mexico. We have high operational control. We're 100% operated. We get 100% working interest and a high NRI of 83.6%. That allows us to control our destiny and be flexible in various commodity environments. We have access to infrastructure and end markets. 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 that it's necessary. We've touched on our HSE stewardship. We've done this in California, and 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. A conservative financial policy. I think this asset certainly can support one times leverage on a long-term basis, and I think we'll use that in the long term on this 50-plus year asset to drive the shareholder returns like we mentioned. That concludes our presentation. Harrison, we'll turn it back over to you for any questions. Yeah. At this point, we'll take Q and A from certain analysts. I see the queue's begun, and we'll start with Lloyd Byrne at Jefferies. This time, if you'd like to ask your question, you can click the raise hand button, which can be found on the black bar at the bottom of your screen. When it's your turn, you will receive a message on your screen from the host allowing you to talk, and then you will hear your name called. Please accept, unmute your audio, and ask your question. Our first question comes from Lloyd Byrne at Jefferies. Your line is unmuted. You may ask your question. Great. Thank you, Jim, Gregory, Harrison. Thanks for the presentation. All this information's 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 four years, Gregory, and just what's the probability that you will or won't need ESPs and then any additional cost that would come with that going forward? As far as the capital for 2027, 2028, I think we forecasted $80 million total and company-wide. That includes additional facility upgrades, some instrumentation. These are 50-year-old facilities, they're 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-$15 million on perf ads. Our F&D cost is super low, but if you just include all the capital, Lloyd, it's about a $4 a barrel F&D cost with all capital, but just as far as drilling completion capital, it's about $0.64. That you can map it out there. Where the capital would ramp after 2029 is when we talk about having drilling rigs out there starting in 2030. According to our plan, that works pretty well as far as generating the free cash flow and so forth. If you look at it from a debt extinguishment model, which is hard for me to say those words, I've always refinanced more than extinguished. From a debt extinguishment model, you've got a lot more operating margin to put capital work in with the drill bit. We'd probably move two drilling rigs out to the larger platforms and start growing production from 2029, 2030, on to 2035. That's the current model. We can accelerate that any point in time if we refinance this debt and covenants or whatever, or 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. To ESPs, focusing on them, they're flexible. Wherever we feel like we need them 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 at the field to the west that we operate at Point Pedernales very successfully. 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. Our gas lift operation is working spectacularly lifting those volumes. We'll just see how the field settles out. No one's ever done this before, shut a giant oil field in for 10 years then put it back on production. There's no literature on it. The Netherland, Sewell engineers and our engineers are learning as we go, we're learning from a very positive plateau. Did I cover everything? Yep. That's very helpful. Let me ask, I have one more quick one, 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? The back end of the curves come up even though maybe they're not 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 do about two to three years of floors, and then say floors is $70. I mean, just from a standpoint. Let's say they cost $5. What we'd sell is six months to 12 months ahead, calls to pay whatever the $5 call would be to cover the cost, make it a costless collar, but we'd roll into that. When we did this in 2003 to 2009 at PXP, it was very successful. We hedged at $25. We sold floors at $25 a barrel, $50 a barrel, $100 a barrel, $125, and we were getting ready to buy some more puts at $150 a barrel. You remember oil caps at $147.50, and then it dropped down to $27.50 at Valentine's Day in 2009. When we closed out all those floors, and we had about $25 a barrel of premiums, we closed out all those floors. We harvested $1.1 billion out of that hedging market, and we paid off our $800 million of debt. 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 the standpoint cover the calls. It's an ongoing live exercise that we've managed very well in the past and we're excited about. The key is you have to have low decline, repeatable production, and repeatable PDP, and that's why this plan works so well operationally with that financial plan. That makes a lot of sense. Sorry if I have one more. Just it's my understanding that DOE and the DOI have a field trip later this week out to Las Flores. Just wondering if there's anything you can comment on there. Does that have to do with the buoy strategies? Does 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. There's also DOTs coming as well. All three secretaries right now are scheduled. Wright, Burgum, and Duffy are all coming out there and so forth. We've got a massive amount of people, 37 folks, so I'm glad we have a big facility to handle them all. We don't really qualify, we found out through the federal government, as a hardship financial case because of all the free cash flow. The financial support is probably not as realistic as anything we talked about. The regulatory support and the operational support has been phenomenal, obviously, with the DPA and so forth. We're discussing several condemnation strategies with all three groups and stuff like that and trying to come to a strategy that everybody likes. Because the federal government's been 100% supportive of us. It's interstate pipelines, DPA, they're committed, and the Justice Department has shown the efforts as well, committed to ensuring our operations are lawful and safe and able to get done. We're excited about having them all out there. If anything comes of it, I'm sure it'll be on Fox News. You guys can read about it. All right. Thank you very much. Thank you. Your next question comes from Michael Scialla from Pickering Energy Partners. Your line is unmuted you can asked your question. Hello, good morning to the Sable team. 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's probably not expecting that every project's going to add 1,000 barrels a day. There seems to have been something that the Sable operating team noticed on these first two perf adds that gave you the confidence to alter the go-forward plan. Maybe could you elaborate on what you saw on these first two projects and maybe speak on how repeatable you think those characteristics are for the remaining prospects? 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 perf and the Massive Chert in red, and it's got the planned perf in yellow. What you always worry about in these things is there any communication, even though the 400 or 600 feet of pay in the Upper Siliceous hasn't been perforated in the field, you always worry about whether there's communication between the reservoirs. And that shale break in between is obviously the key integrity point. Now that we've tested two of them and realized that shale break has tremendous integrity and that the unperfed, undrained Upper Siliceous is not communicating with the Massive Chert, that allowed us to say with confidence that this is something we can put our operational plan on. We're very excited about it. We have 400, 600 feet of pay in a virgin reservoir, basically, in the Upper Siliceous that's had just a few wells drilled on it in different parts of the 77,000 acres. It's a brand-new oil field sitting up on top of the Massive Chert that we've already produced 650 million barrels. I've never seen this before in my life. The aspect to this opportunity, it's once in a lifetime to have this kind of oil and oil recovery for those perforations. Now that we've had two of them on production and they haven't declined, and they're like brand new wells coming on, it's a spectacular opportunity for all the stakeholders at Sable. Great. Appreciate that color. Just to follow up on the strategy change, 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's previously mentioned the opportunity for shareholder returns. Under this new strategy, could you maybe speak about how your capital allocation priorities change, if at all? Yeah. The share returns are obviously, we're all shareholders, and we're very focused on that. What we want to focus on getting the business refinanced and getting it fully on production here this year with all three platforms and have our new reserve report come out at the beginning of 2027 at year-end 2026 with no restrictions, no problems or that type of thing, we know exactly where we are, the investors know where we are and so forth. Then we can look at our debt structure, hopefully pay some debt down by then. We maybe look for some permanent capital in the bond market, that type of thing, beyond this term note, then that would give us an opportunity to kick off our shareholder return program. 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 return that money to our shareholders either in dividends or stock buybacks. Gregory, you want to add anything? No, I think the key there is we've got the underlying free cash flow profile to handle both. We've got the reserve life to not only continue to prosecute a shareholder return plan, but to do it over decades versus some short-term five-year program. Justin, we're all focused on that. Like Jim mentioned, we're all shareholders, and we're going to drive that. The good thing is we've got the asset, the cost structure, and the reserves in place to do it. All right. Thanks again. I'll turn it back. Thank you. Your next question comes from Charles Meade, Johnson Rice. Your line is unmuted you may now asked your question. Yes. Good morning, Jim, to you and your whole team there. Thank you. I wanted to see if you guys will talk a little bit more about your refi process. I recognize it's in process, you might be appropriately sensitive about it. You guys seem pretty confident, for equity investors from the outside looking in, looking at three weeks to a maturity is a little closer shave than most equity investors are used to. Maybe one thread to pull on here is, you guys have, I believe it's on slide 18, footnote four, where you talk about a May 31, 2026 reserve report. Is this the kind of thing that you're just now getting in front of your banks, and that's why we haven't heard anything yet? It's going to be a busy three weeks. Alternatively, is this the kind of thing where your banks have been looking at your reserve report and this is just a kind of pro forma roll forward to May 31? What do the next couple of weeks look like? Yeah, Charles, we've been getting just in time information on the reserve report, but also production history, so forth, make sure that we feel like we support everything. Every day we feel more confident. Okay? The aspect, I wish we had 180 days of production reserve report that all the PDNP would be PDP and so forth. We just ran out of time. We pushed it as far as we possibly could. I had one guy call me, said, "You waited for Iran to kill the negotiations to start the deal?" I said, "No, we had no coverage on that." It's just the way the timing worked out. There's a lot of moving parts here, but we're confident with our banks, JP Morgan, and the group they have together, as far as being able to execute on this plan, with plenty of time to spare. Charles, to answer your question, I can assure you, we're not just now getting in front of the banks. We've had JP Morgan engaged as lead on our refinancing for some time now, over a year. Yeah. I'll also tell you, we have left no stone unturned in terms of federal credit support options. 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 discussions are ongoing, but we don't plan for them to be there to handle our maturity here in June. Yeah. They've matured into operational support versus financial support. Correct. Got it. That's helpful detail. Then, Jim, if I could go back to this, the added perfs in the Upper Siliceous. I think you said a couple times that there were maybe seven. I think you have a lot of penetrations, but maybe only seven perf intervals in that Exxon moved a bit. I wonder if you could talk about the history of that. It looks pretty similar on the logs, and you guys talk about having almost 4x on your historic needs. Is that historic from the siliceous or from the Chert and it's not tested earlier, is that? Remember, Exxon was rolling out their plan, and they got interrupted by the oil spill. Okay? If Exxon had five more years, they'd have rolled through all this stuff. Okay? They got interrupted by the oil spill, just shut down. It's like finding a Ferrari in someone's basement, you just bought the house. It's just sitting there going, "Look at this." We just pick up the baton from there. This isn't hidden camouflage or whatever, just hadn't got to it yet. They only had about a dozen perforations in this thing of 77,000 acres. You've got hundreds of millions of barrels in this Upper Siliceous that we're just going to harvest the old-fashioned way with existing wells and perf adds. Like I said, this is a once in a lifetime opportunity. We've never had a situation like this before, and I'd be surprised unless you have some major dislocation, like an oil spill off offshore California, or find some Middle East field that's been under conflict for 20 years that can be reperfed, that type of thing. It's a very unique situation, and we're happy to take advantage of it for all our stakeholders. Your next question comes from Leo Mariani from Roth Capital. You may now unmute and ask your question. Yeah, good morning here, guys. 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 a straight debt solution will 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 maybe some kind of term loan. Just to clarify, it also sounds like at this point, it's just given the cash flow profile, that federal credit support seems pretty unlikely. Just wanted to clarify those things. Yeah, Leo, I'd say you're right on the federal credit support at this time. I think we are pursuing debt capital markets for this refinancing, and those efforts are led by JP Morgan. Okay. Just wanted to follow up on the buoy. Yeah Needing some regulatory sign-off for this oil buoy here. Just looking at your marketing situation, looks like the oil price realizations, maybe for the rest of the year, seem a little bit lower than expected here. Do you see that this buoy will really improve that? Any comments on what capacity might be on that buoy, and could this dramatically change your price realizations going forward? Just apart from that, is there any opportunity maybe in the next call it year to improve realizations regardless of that buoy, which I know is going to take several years to put in place? Yeah. The marketing optionality will give us better leverage. The world would be our refinery market versus just California. 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 buoy would be up to 150,000 barrels a day. It would be a 24-inch pipeline going back and forth. We'll have pumps for that as max capacity. From a sales standpoint, just matching our capacity we have at Las Flores Canyon. From our standpoint, it's another outlet, 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 of which direction we all want to go. They've been very helpful there, and that's really important strategies there, and the BSEE's part of that as well. We're well-coordinated with them. We just wanted to put a conservative timing on that from a standpoint of going through the process. It'll be done, obviously, during the existing administration of Donald Trump. Okay. That's super helpful. Just last one from me on production. If 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 relative to your guide, just given that your final platform isn't on yet for the year. It certainly seems like you're in good shape with respect to the guidance, if I heard you right on that. Yeah. Leo, also on that too, we got notification by BSEE in late last week or last week about being able to debottleneck some of our gas production. You realize we have gas compressors for gas lift to lift the oil on each individual 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. We're still debottlenecking some of that. There's some upslide to that 46,000 barrels a day number. Once we get all the wells on in Heritage and Harmony that some have been restricted just because we haven't had enough gas to be able to handle the gas they make or haven't been able to have enough compressor gas to allow to activate the gas lift on those. There's still more unwinding to do on Platform Harmony and Heritage. We're really excited about seeing the perf ads at Hondo this summer and see how they come on. Okay. Thank you. Thank you. Your next question comes from Noel Parks from Tuohy Brothers Investment Research. You may now unmute and ask your question. Hi. Good morning. I was interested in the heavy oil potential that you identified in the slides. 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 in hearing more about that. Yeah. Exxon had drilled two wells and completed and produced them out of the heavy oil. Heavy oil, it has a lot of solids with it. It takes a different processing at the surface. Our picking up, we're going to have to upgrade some of our separators and be able to handle the heavy and the solids and some of the screens and so forth. It's not really compatible to produce it with the existing processing facilities we have with the Massive Chert and Upper Siliceous. That's just money and engineering. It's not a big deal. What's amazing about the heavy oil standpoint, having nine to 13 gravity oil that Exxon produced, it's very viscous and it'll flow fantastic. Productivity is just like all the other wells. From that standpoint, haven't been able to produce it, and we haven't seen the down dip oil limit of the heavy oil leg. That's why right now we've proved up over 500, 600 million barrels on the structure. We haven't got to the bottom of it. We don't know how much there is. There could be as much as 1 billion barrels additional of heavy oil that we could add to our reserves. Let's talk about taking the heavy oil out and producing it. We would end up having to sidetrack existing well bores and drill a new wells for the heavy oil portion because of the prolific production out of the Upper Siliceous and Massive Chert. 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 to when we get into strictly being heavy oil and all the Upper Siliceous and Massive Chert are depleted. It's going to be able to be mixed in. It's going to take a little while for us to get all our facilities tuned to where we can do both phases of this oil environment to do. At the same point in time, we're adamant about it, and we're super excited to have that reserve in our back pocket 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 some of the longer, deeper wells to figure out where that oil leg extends. That's 100% upside to our existing story. Great, thanks. I was wondering, when you talked about the repressurization putting off the need for ESPs, does the repressurization alone explain the upside versus your expectations that you've seen in production so far with what's come online? Are there other factors in the mix as well? Yeah, it is for a couple of reasons, because remember, Netherland, Sewell gave us 34,000 barrels a day gross out of the three platforms when trying to turn the field back on. They just put an arbitrary 30% discount for unknown reasons and so forth, just the public engineering discount. Now we're looking, forecasting somewhere upwards of 60,000 barrels a day with Platform Harmony's on, 55,000-60,000 barrels a day. That's all repressurization and reestablishment of the hydrodynamics of the reservoir. One of the key things we've seen, just like the engineering book said, we've seen gas move back into liquid, back into solution based on repressurization. We've had wells that are in an up-dip position in the gas cap that were producing 15 million cubic feet of gas a day, are now producing 1,500 barrels of oil and no gas because the gas cap is shrunk back into the oil, into solution. There's some heavy duty engineering things that are very textbook going on in this repressurization, and they're all positive if you're looking for oil production and liquid production. Far, so good. Great. Thanks a lot. Thank you. Your final question comes from Subash Chandra with StoneX. You may now unmute and ask your question. Hey, Jim. In the past, you had a dividend per share target. Just curious if you're thinking of the world the same way? Yes, we are. Subash, it's just timing, that we talked about earlier. Once we get Exxon financed out, obviously those dividends are prohibited under that term loan and so forth. Once we understand the terms of the new financing. 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 early 2027. Okay, got it. 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. We'll have to address those issues once we have the cash flow. We certainly have the capacity. Also a function of oil price as well. What's the oil price at? We can back into what our free cash flow is and what our capacity will be. Right. Also potential repurchases of shares versus dividends, right? That'll be a debate amongst management and the board on how we prosecute that shareholder return strategy going forward. Got it. Could you remind me, I think the gas handling capacity, at least nominally, was 80 million cubic feet per day, something like that. You addressed that a little bit, where are you with regards to your gas capacity? Yeah. Let's break it down this way. We have gas needs in the field for our gas lift operation. Also, we're sending gas to shore to run our electric cogens and so forth. We have ability to sell gas once our POPCO plant is fully up to speed. That'll be fourth quarter this year, where POPCO will be fully repaired and be able to start selling gas. Somewhere between 80 million and 90 million a day on a sales basis. I got to tell you, Subash, right now, a lot of those gas wells are producing oil. We don't have that much gas to sell. It's going to be more over time as the field normalizes out and the gas production comes up. We'll be selling more oil than we will gas. I would cut that in half in the 40-50 range on the gas sales for next year. Might be a better position to be in. Hopefully, we're surprised that we have so much oil that we don't care about how much gas we sell. If not, and we have more gas, we'll start to sell it up to 80-90 million a day. Okay. Yeah, that's good. Yeah, my final question, just segueing into that. You're not seeing any gas cap yet. On the perfs, you're not seeing higher gas concentrations. So far, the evidence is you're not seeing it. What do you think going forward? Do you expect a higher gas cut on the perfs? Well, two things. Oil fields deplete. We will see some depletion. We will see some pressure decline. We will see some gas production increase as the gas breaks out of solution. The question is when. Is that this year, next year, three years from now, four years from now, whenever it is. Just so far, we've been pleasantly surprised in the last 90 days that there's no visible decline in the field. As we add more gas lift, we're seeing the production response. This has been a beautiful restart, and we're going to ride it as long as it comes out. We'll just be updating people, and we're ready to throw the ESPs in just to maintain production at a low cost to keep our cash flow maximized. We got a lot more than eight to do over time, depending on what the field does. This is just the beginning of a long, long novel of opportunities and harvest the field as the most cash flow maximizing strategy possible. Thanks, Jim. Okay. 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 get it out to all our stakeholders to what the value's been created here at Sable Offshore. We really appreciate the federal government support of all our operations and prioritizing this project under the National Energy Dominance Council as far as one of the key projects behind our federal government support. We're going to continue to maximize that for all the Sable 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 and the courts. Thank you all, and we'll look forward to seeing you soon. Bye