Good morning, everyone. My name is Kevin Andrus with EnerCom. It's my great pleasure to introduce our next speaker, Ben Rodgers, CFO of APA. They have many exciting opportunities that they're drilling. Without further ado, I'll turn it over to Ben.
There I am. All right. Good morning. Always good to be in Denver, be at EnerCom. A lot of familiar faces, a lot of new faces. It's definitely cooler here than it is in Houston. Unfortunately, only here for 24 hours, but we'll start with this page here, the overview of APA Corporation or Apache. Been around for over 70 years, kind of one of the household names in the oil and gas space. A lot of you have heard of Apache. Very different from years past. I'll go through that from a portfolio standpoint. You can see here diversified portfolio around the globe, not only diversity from a commodity standpoint of both oil and gas, but diverse from geographies and also unconventional and conventional assets.
We believe that diversity is a strength from an asset perspective, giving access to different pricing points around the globe, ability to allocate capital across different assets, and we think that that's a strength in moving into what could be a post-shale era in the coming years. This year's capital budget is $2.1 billion. The majority of that is going towards our development assets in the Permian and in Egypt. We have a target of approximately 10%-15% of each year's capital budget going towards exploration. It's a little less this year. I'll talk about how that's increasing next year. You can see here five exploration and appraisal wells planned in some of the assets that we have here. I'll talk about those. That excludes appraisal work that we're doing in the Permian. It excludes exploration work that we're doing in Egypt.
That is just assets in Alaska, Suriname, and Uruguay for those five wells there. Just under $1 billion spent on exploration and appraisal in the past six years. We believe in exploration. I'll talk about the benefits of that here in a little bit. We are one of the few that actually stands by the E in E&P, and believe that there's a lot of value that can be generated from exploring around the globe for oil and gas. To talk here about our investment case, we have underpinning our assets are stable and predictable assets in the Permian and in Egypt. We've been in Egypt for over three decades. We are the largest oil producer in Egypt, the largest onshore acreage holder there. Actually, the largest U.S. investor in the country of Egypt. We've got a great relationship with the country there.
We have a partner there that owns a third of the business in Sinopec, and so it has been a cash cow for many years. Given the PSC mechanics there, actually generates a lot of very steady free cash flow for us that we can deploy in other areas. We've been in the Permian for over a decade. John Christmann, who's with us today, used to run that asset before he was named CEO, and it's a great position for us. We added to that position in 2022 with a bolt-on acquisition in the Delaware Basin. We added to that in 2024 with the purchase and integration of Callon. Those two assets provide a steady base of free cash flow that we're able to deploy across different priorities that I'll get to in a little bit.
Very capital efficient asset base, very strong reinvestment rates in the Permian and in Egypt. That is driven by our cost leadership position. About a year and a half ago, beginning in 2025, we outlined a target that by the end of 2027, we would reduce what we call our controllable spend, capital, LOE and G&A, our cost burden, by $350 million on a run rate basis by the end of 2027. We actually achieved that in one year. We reached $350 million of run rate savings across those three cost buckets by the end of 2025. When we entered 2026, we said, actually, that is now $450 million as we exit 2026. Then in August, we increased that to $500 million.
$500 million of structural true costs coming out of the system based on how we develop the assets, how we operate the assets, and how we manage the business. Truly are a cost leader now in the Permian and in Egypt. We have streamlined the way that we manage the business from a G&A perspective. Really think that we are a cost leader now and moving into 2027, you look at that, this $500 million of costs that have come out of the system. On top of that, $175 million of annualized interest expense, also lower. So $700 million lower cash costs as we exit this year going into 2027. Very strong cash flow profile because of that and what we've done on the cost side. We have visible organic oil growth, keeping Permian relatively flat for the next few years.
Egypt on a very modest gross oil decline. North Sea, also very modest decline, but we have growth coming now in less than two years from Suriname Gran Morgu. That was an exploration play. I'll walk through the timeline of Suriname here in a few slides, but we've been spending development capital. TotalEnergies has been spending a lot of development capital on our behalf because of a carry agreement that we negotiated with TotalEnergies, bringing them in as a 50/50 partner back in 2020. We've been spending those development capitals since the FID in 2024. There's oil growth coming from that capital spend, and we've got over 5% oil CAGR over the next three years. Lots of exploration upside with catalysts in Suriname, Alaska, Uruguay.
Again, that doesn't include what we're doing in Egypt on the gas and the oil side for exploring there in Egypt as well as in the Permian Basin to where earlier this year we outlined 10 years of economic inventory. We've got just as many locations and technical upside that the team is focusing on appraising and moving those technical locations where we know there are hydrocarbons present. It could just be spacing tests or other analog tests that we need to do to move those into economic inventory. We think that a lot of those will work and will mean that we have much more than 10 years of drilling inventory in the Permian Basin. Those two items in Egypt and Permian are on top of what we're doing for the exploration assets you see listed here.
All of that combined, very strong base where we're able to provide strong shareholder returns as well as a very strong balance sheet. Quick highlights here. I won't read everything, but we did have a very strong second quarter, a strong first half to the year. We printed $1.2 billion of free cash flow in the first half. A lot of that, as you can see, was used towards paying down debt. We paid down $750 million of debt in the first half of the year. We increased our run rate cost savings. I mentioned that. In the Permian Basin, if you go back to November of last year when we provided the preview for 2026, we said that about $1.3 billion of capital will support 120,000 bbl a day in the Permian.
We increased that in February, we increased that in May, and again in August, increasing what our production outlook is now at 123,000 bbl a day, keeping capital flat the entire time. So spending $1.3 billion and from that, because of the work the team has done, much more capital efficient, and the productivity from the base as well as the new wells being drilled. 123,000 bbl is now what we expect for the full year in Permian after two quarters in a row of beating our guidance that we've put out there. On the strategic progress side, I talked about the debt reduction in Egypt. About a little under two years ago, we renegotiated our price agreement in Egypt. It was fixed for decades before that. It's much higher now, so we're incentivized to not only explore for, but develop gas.
Over the past 18 months now, about half of our gas is receiving the new price that we negotiated in Egypt. I mentioned before that the exploration dollars I outlined exclude exploring for gas in Egypt. Very successful exploration portfolio there. We're excited about where that's going. In the second quarter, we announced an acquisition of Savant in Alaska on the North Slope. With our partner Bill Armstrong and Santos, we have a very large acreage position on the North Slope in Alaska. We've got two discoveries, and in those discoveries, we've found very high-quality reservoir, and we're very excited about where we're going to go in Alaska moving forward. This acquisition brings a lot of infrastructure, midstream assets. It's got 40,000 bbl a day of crude oil processing, an 80,000 bbl a day crude pipeline that connects into TAPS.
It also brings other infrastructure items like gravel pads, a dock, an airstrip. A lot of synergies we can use for this upcoming winter drilling season. We are drilling two wells in Alaska. I will talk about that in a little bit. Obviously, moving forward, what that can bring from an upside of defraying development costs and potential timeline if we get to an FID for a development in Alaska. We are very excited. Industry is very excited. There has been a lot of industry activity moving to the North Slope in Alaska. We were one of the first in the recent move up there. We were one of the first movers, and we have been in Alaska now for over three years, and we are very excited about the prospectivity there. We also announced a partnership with Eni in OFF-6. It is one of the blocks that is offshore Uruguay.
We have two ownership positions in Uruguay. One is in OFF-4, where we are 50/50 with Shell. The other one now we are 60/40 with Eni. We will operate the exploration well that is planned for the second half of next year. In that agreement that we signed with Eni, they are going to carry most of the cost of that well. Expensive well. It is an offshore well, not too dissimilar from what we are drilling up the coastline around in Suriname, but very excited about what we are doing in Uruguay as well, and also with Eni, fantastic partner. Viewed from a lot of industry experts as one of the best in exploration around the globe. Case for exploration. We explore. It has been part of our DNA for a long time.
We think that the benefits from exploration, building out a diverse portfolio, I talked about the benefits of a diverse portfolio. You look at the entry costs in exploration, much lower full cycle breakevens than if you are doing it through A&D or M&A and having to pay up for acreage or pay up because someone else has developed it before you, and you would like to take the reins and move forward. We start from the beginning and think that there is a lot of alpha that can be generated for our shareholders by having that low cost of entry and keeping the full cycle cost low. I will talk about what that means in Suriname compared to other assets here in a little bit.
This slide, and a couple of numbers here, really the takeaway, exploration spend in industry-wide across the globe is down significantly over the past 10 + years. Proved reserve life. You look at the reserve replacement, but the life of the reserves that are posted by public companies, also down pretty significantly over the past 10 years. If you project out, this is from ExxonMobil's most recent presentation, if you project out production and no more exploration dollars or development dollars, appraisal dollars spent on identified discoveries, production globally will decrease 4% per year moving forward. That means that for over a decade, you have had billions of dollars that have not been spent in replacing the production and reserves that we know the world is going to need.
What is paramount for the strategy for Apache is we believe that for decades, from where we sit now, from decades beyond, oil and gas demand will continue to grow. Look on the right-hand side. The IEA, five years ago, because of what was outlined from Net Zero, a lot of ESG pressure under a different administration. In 2021, the IEA said that 2030 demand for oil would be less than 75 million barrels a day. Fast-forward to where we are now, reality sets in, and they say, "Just kidding.
Instead of 75 million barrels a day, actually demand in 2030 is going to be over 105 million barrels a day, and that is going to continue to grow at least until 2050." There is a known demand base for hydrocarbons around the globe that is true and is coming, and with demand growing and potential supply coming, that could come to a crossroads in five or 10 years because of the lack of dollars that have been spent to explore for new oil and new gas. We have not done that. We have stayed. You can see what has not changed. Apache strategy. We use the cash-generating businesses in Egypt and in the Permian to fund exploration. That has benefited from having the discoveries, getting the partnership with TotalEnergies in Suriname, and now new reserves coming in 2028, and then potential beyond that in Alaska and in Uruguay.
You can see that here. Cash generating base. Permian business, Egypt business. We have a gas trading business, which this year is going to do $950 million of cash flow net to us. Last year, it did just under $700 million. The year before that, it did about $500 million . These are takeaway pipes in the Permian, as well as an LNG contract that we have with Cheniere. Those two businesses combined have generated billions of dollars of cash flow for us over the past few years.
That, along with our upstream assets, being able to invest in future assets, invest in the future of the company, thinking about how do we replace our reserves in five and 10 years, how do we replace our production in five and 10 years, we are not beholden to only doing that through M&A like a lot of Shell players are. Shareholder returns. I have talked about very strong shareholder returns over the past few years. We have a shareholder return framework. Excuse me. We return a minimum of 60% of our free cash flow to shareholders every year. We have done that since 2021. We are going to do that moving forward. When I joined Apache about 8.5 years ago, we had almost $9 billion of debt. We are going to end this year close to $3 billion of debt. Very strong balance sheet.
A lot of fixed cost savings that come with that, but a lot of financial flexibility as you move forward, as you go through different commodity cycles to be opportunistic around assets, around share buybacks, and other things. This is a slide on Suriname. I thought it would be helpful. In the upper left, you can see the timeline. Exploration, both onshore and offshore, takes time. Varying different time frames, depending on the asset, depending on the country you are in, depending on the rock quality and the type of hydrocarbon you are producing. We entered Suriname in 2015. We spud our first exploration well in Block 58 in 2019, signed up TotalEnergies as a partner in late 2019 as well. 2020, had a discovery. COVID hits. Oil prices go down. We continued to explore on the block through 2020, 2021.
2022, we get into appraising some of the discoveries, and then we announced FID with TotalEnergies in October of 2024, and then fast-forward to where that means first oil in 2028, mid-2028. You look at a proxy for other offshore developments, the Liza field or the Liza development in the Stabroek Block right next to us in Guyana with ExxonMobil. Between FID and first oil, they were 3.5 years. We are going to be a little bit more than that, 3.75 years between FID and first oil, but our boat is almost 2 x the size. We are building a 220,000 bbl a day FPSO for Block 58 for this first development that we have on Gran Morgu. 2027, we expect to continue to explore with TotalEnergies in the Block. There is a lot of new prospects that we have identified with TotalEnergies.
We learned that through the appraisal of Krabdagu, through the appraisal of Sapakara, the wells that are underpinning the development. We know that there are other prospects to explore here. We are excited about getting back out there next year with our partner. I talked about the low full cycle costs from exploration. Our break even post FID for this with TotalEnergies is $30 a bbl. That is some of the most competitive barrels that will be produced moving forward. We can extend the plateau on this through exploration. There is a potential to underwrite a new project as well that helps that break even for dollars that we spend. We are very excited about this. We are less than two years now from first oil in Suriname. Fantastic project. TotalEnergies is a great partner who operates this now, and we are excited there is more to come in Suriname.
I will close with this slide before we go to a breakout room for Q&A. This is a good snapshot for what we are doing on the exploration side around the globe. I mentioned Suriname, a minimum of two wells next year. Sorry about that. Dry heat in Colorado. The wet heat in Houston, I do not do this. I talked about what we are doing in Suriname, two wells next year. There is a lot more to do even after 2027 going into 2028. When the first oil comes on the exploration side, there has been multiple prospects identified by both our subsurface team as well as TotalEnergies'. We are going to be exploring in Block 58 for many, many years. Alaska, two-well program. We have been talking about this for a long time. One of those is appraising Sockeye.
Sockeye was a discovery that we had last year, and we are going to go appraise that now. We took a pause on the drilling program in Alaska this winter because there were a lot of different seismic packages that we had across our acreage footprint. We said the right thing to do was to combine the seismic, make sure that we have a very clear picture of what we're doing on the acreage footprint. That was the right thing to do. It gave us actually a more clear picture of Sockeye, where to go appraise Sockeye next. Chinook is an exploration well and gave us a lot more information for what we're going to be doing on the exploration well for Chinook. We will be drilling those wells in 2027. We laid ice roads. We will be laying ice roads for those this November and December.
We'll start the drilling program up there, starts in January and February. We'll spud those two wells. Lastly, Uruguay. I talked about the partnership that we signed with Eni. We will operate that exploration well. We have 60% of that block, Eni 40%. We will be funding because of the carry agreement we signed with them much, much less than 60%. Most of that well will be covered by Eni. We're very excited. A lot of industry eyes on that well being drilled. Uruguayan government has been very helpful as we've moved through the permitting process, and we're very excited about Uruguay. Again, ongoing appraisal in the Permian, very excited about that. We've got more than 10 years of inventory.
I fully expect that in February of 2027 and February of 2028, because of the work the team does, we can sit here and continue to say we still have 10 years of inventory because we're more than replacing the wells that we've drilled because of our position there. We need to go do some appraisal work to get there, but fully expect that to happen. I talked about what we're doing in Egypt on the gas exploration side as well as on the oil side on our 7 million acre footprint there in the Western desert. Great portfolio. We think it's differentiated from a lot of our peers. We think that the market is starting to turn and give value to these large-scale exploration assets. I would put our exploration portfolio against any one of our peers out there that does explore. It's a great portfolio. It's diversified.
We're very excited. We've diversified from a partner standpoint as well and are excited about 2027 and beyond. I'll stop there. We're going to have a breakout session, I think in Lawrence B room, and we'll go to Q&A. Thank you all.