การประชุมแถลงผลประกอบการไตรมาส 3/2026 ของ APA: ปรับเพิ่มแนวโน้มกระแสเงินสดอิสระเป็น 2.9 พันล้านดอลลาร์

ประเด็นสำคัญ

• APA Corporation รายงานกำไรสุทธิส่วนที่เป็นของผู้ถือหุ้นสามัญในไตรมาส 3/2026 ที่ 698 ล้านดอลลาร์ หรือ 2.00 ดอลลาร์ต่อหุ้นปรับลด ขณะที่กำไรสุทธิที่ปรับปรุงแล้วอยู่ที่ 676 ล้านดอลลาร์ หรือ 1.94 ดอลลาร์ต่อหุ้นปรับลด
• กระแสเงินสดอิสระประจำไตรมาสแตะระดับ 699 ล้านดอลลาร์ ส่งผลให้กระแสเงินสดอิสระตั้งแต่ต้นปีจนถึงปัจจุบันสูงกว่า 1.9 พันล้านดอลลาร์ ทั้งนี้ ฝ่ายบริหารได้ปรับเพิ่มคาดการณ์กระแสเงินสดอิสระสำหรับปี 2026 ขึ้น 600 ล้านดอลลาร์ สู่ระดับ 2.9 พันล้านดอลลาร์ โดยระบุถึงการคาดการณ์ปริมาณการผลิตในสหรัฐฯ และอียิปต์ที่สูงขึ้น รวมถึงราคาสินค้าโภคภัณฑ์ที่แข็งแกร่งขึ้น
• APA จ่ายผลตอบแทนคืนสู่ผู้ถือหุ้น 537 ล้านดอลลาร์ในระหว่างไตรมาส ซึ่งรวมถึงการซื้อหุ้นคืนประมาณ 450 ล้านดอลลาร์ และเงินปันผล 87 ล้านดอลลาร์ และเมื่อประเมินจากราคาซื้อขายล่วงหน้า (strip pricing) ในปัจจุบัน ฝ่ายบริหารคาดว่าจะมีการซื้อหุ้นคืนเพิ่มเติมอีกราว 650 ล้านดอลลาร์ภายในสิ้นปีนี้
• ปริมาณการผลิตน้ำมันในสหรัฐฯ อยู่ที่ 128,000 บาร์เรลต่อวัน ซึ่งสูงกว่าคาดการณ์ของบริษัท โดยได้แรงหนุนจากระยะเวลาเดินเครื่องผลิตที่อยู่ในระดับสูง การเริ่มเชื่อมต่อหลุมผลิตเข้าสู่ระบบท่อส่งได้เร็วกว่ากำหนด และผลการดำเนินงานที่แข็งแกร่งของหลุมผลิตใหม่ ส่งผลให้คาดการณ์ปริมาณการผลิตน้ำมันในสหรัฐฯ ตลอดทั้งปีปรับเพิ่มขึ้นเป็น 124,000 บาร์เรลต่อวัน
• หนี้สินรวมลดลงประมาณ 450 ล้านดอลลาร์ในไตรมาส 3 สู่ระดับ 3.3 พันล้านดอลลาร์ ขณะที่หนี้สินสุทธิปิดที่ 3.2 พันล้านดอลลาร์ โดย APA กำลังเข้าใกล้เป้าหมายหนี้สินสุทธิที่ 3 พันล้านดอลลาร์ และได้กำหนดเป้าหมายระยะยาวใหม่ไว้ที่ 2 พันล้านดอลลาร์
• งบลงทุนขั้นต้นในธุรกิจต้นน้ำประจำปี 2027 ของฝ่ายบริหารอยู่ที่ประมาณ 2.5 พันล้านดอลลาร์ โดยการพัฒนาและการสำรวจโครงการ GranMorgu คิดเป็นสัดส่วนราว 60% ของงบประมาณที่เพิ่มขึ้นจากปี 2026 ขณะที่ปริมาณการผลิตในสหรัฐฯ และอียิปต์คาดว่าจะทรงตัวโดยรวมเมื่อเทียบรายปี

ข้อมูลทางการเงินที่สำคัญ

ผลการดำเนินงานทางธุรกิจและการปฏิบัติการ

สหรัฐอเมริกา

ปริมาณการผลิตน้ำมันในสหรัฐฯ เฉลี่ยอยู่ที่ 128,000 บาร์เรลต่อวัน ขณะที่ปริมาณการผลิตรวมในสหรัฐฯ แตะ 294,000 BOE ต่อวัน ซึ่งตัวเลขทั้งสองสูงกว่าคาดการณ์ของ APA โดยฝ่ายบริหารระบุว่าผลการดำเนินงานดังกล่าวเป็นผลมาจากระยะเวลาเดินเครื่องผลิตที่อยู่ในระดับสูง การเริ่มเชื่อมต่อหลุมผลิตเข้าสู่ระบบท่อส่งได้เร็วกว่ากำหนด และผลลัพธ์ที่แข็งแกร่งของหลุมผลิตใหม่

ประสิทธิภาพการขุดเจาะและการทำให้หลุมพร้อมผลิตในแอ่ง Permian ช่วยเพิ่มประสิทธิภาพการใช้เงินลงทุน โดย APA มีแผนที่จะเพิ่มการดำเนินงานในปี 2027 พร้อมจัดสรรสัดส่วนการลงทุนไปยังแอ่ง Delaware มากขึ้น ปัจจุบันบริษัทดำเนินงานแท่นขุดเจาะ 3 แท่นในแอ่ง Midland และ 1 แท่นในแอ่ง Delaware โดยคาดว่าจะเพิ่มแท่นขุดเจาะอีก 2 แท่นในช่วงเริ่มต้นปี 2027

ฝ่ายบริหารเปิดเผยว่า สัดส่วนการดำเนินงานในปัจจุบันอยู่ที่ประมาณ 85% ในแอ่ง Midland และ 15% ในแอ่ง Delaware โดยคาดว่าจะปรับเปลี่ยนไปสู่สัดส่วนราว 2 ใน 3 ในแอ่ง Midland และ 1 ใน 3 ในแอ่ง Delaware ในปี 2027 พร้อมตั้งเป้าสัดส่วนคลังหลุมผลิตในระยะยาวที่ 60% ในแอ่ง Midland และ 40% ในแอ่ง Delaware

อียิปต์

ปริมาณการผลิตรวมในอียิปต์ค่อนข้างทรงตัวเมื่อเทียบกับไตรมาสก่อนหน้าที่ 206,000 BOE ต่อวัน ขณะที่ปริมาณการผลิตก๊าซรวมอยู่ที่ 542 ล้านลูกบาศก์ฟุตต่อวัน ซึ่งสูงกว่าคาดการณ์ โดยได้รับแรงหนุนจากประสิทธิภาพของหลุมผลิตและปริมาณการผลิตพื้นฐานที่มีเสถียรภาพมากขึ้น

ราคาจำหน่ายก๊าซจริงเฉลี่ยเพิ่มขึ้นเป็น 4.34 ดอลลาร์ต่อ Mcf จาก 4.23 ดอลลาร์ในไตรมาส 2 ด้านปริมาณการผลิตที่ปรับปรุงแล้วอยู่ที่ประมาณ 64,000 BOE ต่อวัน ซึ่งต่ำกว่าคาดการณ์เล็กน้อย เนื่องจากราคาน้ำมันที่สูงขึ้นส่งผลกระทบต่อสัดส่วนปริมาณผลผลิตตามสัญญาแบ่งปันผลผลิต

APA กำลังดำเนินงานแท่นซ่อมบำรุงหลุมผลิตระหว่าง 15 ถึง 20 แท่นในอียิปต์ โดยบริษัทระบุว่างวดงานที่เสร็จสิ้นต่อแท่นซ่อมบำรุงเพิ่มขึ้น 23% ซึ่งช่วยลดงานค้างสะสมและสนับสนุนเสถียรภาพของการผลิตพื้นฐาน

ซูรินาเมและโครงการ GranMorgu

ฝ่ายบริหารระบุว่า โครงการ GranMorgu ยังคงดำเนินงานภายใต้งบประมาณและเป็นไปตามกำหนดเวลาที่จะเริ่มสูบน้ำมันครั้งแรกในช่วงกลางปี 2028 ทั้งนี้ งบลงทุนเพื่อการพัฒนาในไตรมาส 3 อยู่ที่ประมาณ 40 ล้านดอลลาร์ ซึ่งต่ำกว่าคาดการณ์เนื่องจากการส่งมอบอุปกรณ์และการปรับปรุงแท่นขุดเจาะทำให้รายจ่ายบางส่วนเลื่อนไปอยู่ในไตรมาส 4 ขณะที่แนวโน้มตลอดทั้งปียังคงไม่มีการเปลี่ยนแปลง

ภายใต้ข้อตกลง carry agreement ของ APA ร่วมกับ Total บริษัทจะสนับสนุนเงินทุน 10% ของงบพัฒนาโครงการ GranMorgu โดยยังคงถือสัดส่วนสิทธิการร่วมทุนอยู่ที่ 40% ทั้งนี้ บริษัทมีแผนขุดเจาะหลุมสำรวจในซูรินาเม 2 หลุมในปี 2027 เพื่อค้นหาแหล่งทรัพยากรเพิ่มเติมที่อาจช่วยยืดระยะเวลาการผลิตสูงสุดของ GranMorgu หรือสนับสนุนการพัฒนาโครงการใหม่อีกแห่ง

การสำรวจ

APA มีแผนขุดเจาะหลุมสำรวจ 1 หลุมที่แหล่ง Chinook และการทดสอบประเมินผลการค้นพบแหล่ง Sockeye ผ่านหลุม Hungry Horse ในรัฐอลาสกา โดยฝ่ายบริหารระบุว่าหลุมขยายขอบเขตของ Sockeye ซึ่งอยู่ห่างออกไปกว่า 6 ไมล์นั้น มุ่งเป้าไปยังพื้นที่ซึ่งข้อมูลคลื่นไหวสะเทือนบ่งชี้ว่าอาจมีความหนาของชั้นหินมากกว่าตำแหน่งที่ค้นพบในเบื้องต้น

ในอุรุกวัย APA คาดว่าจะขุดเจาะหลุม OFF-6 ร่วมกับ Eni ในช่วงปลายปี 2027 โดยใช้เรือขุดเจาะ BlackHawk ของ Noble โดย APA จะถือสัดส่วน 60% ในแปลงสัมปทาน และ Eni ถือ 40% ซึ่ง Eni จะเป็นผู้รับผิดชอบค่าใช้จ่ายในการขุดเจาะหลุมเป็นส่วนใหญ่ ทั้งนี้ โครงการดังกล่าวจะทดสอบระบบปิโตรเลียมยุคครีเทเชียสในทะเลน้ำลึก ซึ่งเทียบเคียงได้กับการค้นพบบริเวณขอบทวีปแอตแลนติกฝั่งแอฟริกา

คาดการณ์ของฝ่ายบริหาร

• ฝ่ายบริหารคาดว่าปริมาณการผลิตน้ำมันในสหรัฐฯ ประจำไตรมาส 4 จะชะลอตัวลง เนื่องจากจังหวะเวลาในการเชื่อมต่อหลุมผลิตเข้าสู่ระบบท่อส่งและผลกระทบจากสภาพอากาศตามฤดูกาล
• คาดการณ์ปริมาณการผลิตน้ำมันในสหรัฐฯ ตลอดทั้งปี 2026 ปรับเพิ่มขึ้นเป็น 124,000 บาร์เรลต่อวัน สูงกว่ากรอบเดิมที่ 120,000 ถึง 122,000 บาร์เรลต่อวัน
• ปริมาณการผลิตรวมหน่วย BOE ในอียิปต์คาดว่าจะเพิ่มขึ้นเล็กน้อยในไตรมาส 4 และตลอดทั้งปี
• คาดการณ์งบลงทุนธุรกิจต้นน้ำตลอดทั้งปี 2026 ปรับเพิ่มขึ้น 30 ล้านดอลลาร์ สู่ระดับ 2.1 พันล้านดอลลาร์ ขณะที่คาดการณ์การใช้จ่ายสำหรับภาระผูกพันในการรื้อถอนสินทรัพย์ปรับลดลง 15 ล้านดอลลาร์ เนื่องจากการดำเนินงานบางส่วนในทะเลเหนือถูกเลื่อนออกไป
• คาดการณ์ค่าใช้จ่ายในการดำเนินงานสัมปทานตลอดทั้งปีปรับเพิ่มขึ้น 25 ล้านดอลลาร์ โดยมีสาเหตุหลักมาจากการจัดสรรค่าตอบแทนในรูปแบบหุ้นที่สูงขึ้นเข้าสู่ LOE ทั้งนี้ ฝ่ายบริหารระบุว่าผลการดำเนินงานด้านต้นทุนการดำเนินงานพื้นฐานยังคงแข็งแกร่ง
• งบลงทุนขั้นต้นในธุรกิจต้นน้ำปี 2027 อยู่ที่ประมาณ 2.5 พันล้านดอลลาร์ โดยฝ่ายบริหารคาดว่าปริมาณการผลิตในสหรัฐฯ และอียิปต์จะใกล้เคียงเดิมเมื่อเทียบรายปี
• งบค่าใช้จ่ายด้านการสำรวจคาดว่าจะกลับมาอยู่ที่ 10%–15% ของงบลงทุนธุรกิจต้นน้ำประจำปีในปี 2027
• APA คาดว่าจะบรรลุการประหยัดต้นทุนแบบปรับเป็นรายปีได้ถึง 500 ล้านดอลลาร์ภายในสิ้นปี 2026 และเมื่อรวมกับการประหยัดดอกเบี้ยจ่ายแบบปรับเป็นรายปีอีกกว่า 180 ล้านดอลลาร์ จะทำให้ยอดการประหยัดต้นทุนรวมแบบปรับเป็นรายปีอยู่ที่ประมาณ 680 ล้านดอลลาร์ เมื่อเทียบกับโครงสร้างต้นทุนของบริษัท ณ สิ้นปี 2024
• ฝ่ายบริหารยังคงมุ่งมั่นที่จะส่งมอบผลตอบแทนอย่างน้อย 60% ของกระแสเงินสดอิสระประจำปีคืนสู่ผู้ถือหุ้น ควบคู่ไปกับการลดหนี้สินสุทธิลงสู่เป้าหมายใหม่ที่ 2 พันล้านดอลลาร์

ความเสี่ยงและประเด็นที่ต้องจับตา

• กระแสเงินสดอิสระ ส่วนแบ่งกำไรจากการค้าก๊าซ และจังหวะเวลาในการลดหนี้ของ APA ยังคงอ่อนไหวต่อราคาสินค้าโภคภัณฑ์และราคาซื้อขายล่วงหน้า โดยฝ่ายบริหารระบุว่าเป้าหมายหนี้สินสุทธิ 2 พันล้านดอลลาร์อาจบรรลุได้ภายในสิ้นทศวรรษนี้ที่ระดับราคากลางวัฏจักร หรืออาจเร็วกว่านั้นหากราคาปรับตัวสูงขึ้น
• งบประมาณขั้นต้นสำหรับแอ่ง Permian ในปี 2027 ได้รวมอัตราเงินเฟ้อด้านต้นทุนในระดับหลักเดียวช่วงกลางไว้แล้ว แต่ยังไม่รวมการประหยัดต้นทุนที่อาจเกิดขึ้นจากการถ่ายโอนประสิทธิภาพที่เพิ่มขึ้นจากแอ่ง Midland ไปยังแอ่ง Delaware ในแนวโน้มดังกล่าว
• ฝ่ายบริหารยังคงติดตามสถานการณ์ความมั่นคงในภูมิภาคที่ส่งผลกระทบต่ออียิปต์อย่างต่อเนื่อง โดยระบุว่าความปลอดภัยของพนักงานมีความสำคัญสูงสุดท่ามกลางความขัดแย้งในตะวันออกกลางและทะเลแดง
• ภาระผูกพันในการรื้อถอนแท่นผลิตคาดว่าจะยังคงอยู่ที่เกือบ 300 ล้านดอลลาร์ในปี 2027 ซึ่งใกล้เคียงกับปี 2026 โดยการดำเนินงานในทะเลเหนือจะยังคงดำเนินต่อไปอีกหลายปี
• โครงการสำรวจในอลาสกา ซูรินาเม และอุรุกวัย ยังคงขึ้นอยู่กับผลการขุดเจาะ ทั้งนี้ APA ยังไม่ได้เปิดเผยเกณฑ์ปริมาณทรัพยากรขั้นต่ำหรือกรอบการตัดสินใจพัฒนาโครงการในอลาสกา
• โครงการ GranMorgu ยังคงมีความเสี่ยงด้านการดำเนินงานและกำหนดการ แม้ว่าฝ่ายบริหารจะระบุว่าโครงการยังคงดำเนินงานตามงบประมาณและตามกำหนดเวลาในปัจจุบันก็ตาม

ไฮไลต์ช่วงถาม-ตอบกับนักวิเคราะห์

• โอกาสการเติบโตในซูรินาเม: ฝ่ายบริหารระบุว่าเป้าหมายการสำรวจที่วางแผนไว้เป็นแหล่งกักเก็บประเภทเดียวกันและมีอายุหินเดียวกับแหล่ง Krabdagu และ Sapakara โดยหลุมเหล่านี้อยู่ในพื้นที่พัฒนาเดิมและคาดว่าจะสามารถนำค่าใช้จ่ายมาหักลดหย่อนได้ภายใต้โครงการ หากประสบความสำเร็จก็อาจช่วยยืดระยะเวลาการผลิตสูงสุดออกไป หรือรองรับโครงสร้างพื้นฐานเพิ่มเติม
• การประเมินผลในอลาสกา: APA ระบุว่าแหล่ง King Street และ Sockeye ได้ยืนยันระบบปิโตรเลียมที่ยังทำงานอยู่ และช่วยปรับเทียบการแปลความหมายข้อมูลคลื่นไหวสะเทือน อย่างไรก็ตาม ฝ่ายบริหารได้เตือนว่าไม่ควรมองว่าร่องรอยไฮโดรคาร์บอนในระดับตื้นกว่าของ King Street จะช่วยลดความเสี่ยงของแหล่ง Chinook โดยตรง
• ประสิทธิภาพการใช้เงินลงทุนในแอ่ง Permian: APA มองเห็นศักยภาพในการเพิ่มประสิทธิภาพเพิ่มเติมในแอ่ง Delaware แต่ยังไม่ได้รวมผลประโยชน์ที่อาจเกิดขึ้นเหล่านั้นไว้ในแนวโน้มขั้นต้นปี 2027 โดยบริษัทมีแผนจะประเมินว่าแนวทางการขุดเจาะ การทำให้หลุมพร้อมผลิต และสิ่งอำนวยความสะดวกในแอ่ง Midland สามารถนำมาปรับใช้ได้หรือไม่
• กลยุทธ์งบดุล: ฝ่ายบริหารระบุว่าเป้าหมายหนี้สินสุทธิใหม่ที่ 2 พันล้านดอลลาร์มีจุดประสงค์เพื่อรักษาความยืดหยุ่นสำหรับการพัฒนาโครงการในอนาคต ควบคู่ไปกับการรักษาระดับผลตอบแทนแก่ผู้ถือหุ้น โดย APA ไม่มีแผนที่จะสะสมและถือครองเงินสดจำนวนมากไว้เป็นเวลานาน และจะยังคงมองหาจังหวะโอกาสที่เหมาะสมในการซื้อคืนตราสารหนี้
• การประหยัดต้นทุนการดำเนินงาน: โครงการขยายและปรับปรุงพื้นที่เดิมในแอ่ง Permian มูลค่าประมาณ 100 ล้านดอลลาร์ คาดว่าจะช่วยลดต้นทุน LOE ได้ราว 40 ล้านดอลลาร์ต่อปีแบบปรับเป็นรายปี โครงการเหล่านี้รวมถึงการเปลี่ยนปั๊มจุ่มไฟฟ้าเป็นระบบยกก๊าซ การบำบัดก๊าซขนาดใหญ่ขึ้น และการควบรวมสิ่งอำนวยความสะดวก
• การค้าก๊าซ: ฝ่ายบริหารคาดว่าพอร์ตโฟลิโอดังกล่าวจะสร้างกระแสเงินสดก่อนหักภาษีได้ประมาณ 950 ล้านดอลลาร์ในปี 2027 ตามราคาซื้อขายล่วงหน้าที่อ้างอิง ซึ่งรวมถึงการประกันความเสี่ยงส่วนต่างราคา ทั้งนี้ สัดส่วนการสร้างรายได้กำลังเปลี่ยนไปเนื่องจากกำลังการขนส่งผ่านท่อส่งในแอ่ง Permian เพิ่มขึ้นและราคาฮับ Waha ปรับตัวแข็งแกร่งขึ้น

บทถอดเสียงการประชุมแถลงผลประกอบการฉบับเต็ม

บทถอดเสียงฉบับเต็มของการประชุมทางโทรศัพท์ผลประกอบการ

คำชี้แจงจากฝ่ายบริหาร

Operator

Good day, and welcome to APA Corporation's Third Quarter 2026 Financial and Operational Results.

[Operator Instructions] Please note this call is being recorded. I would now like to turn the call over to Stephane Aka, Managing Director of Investor Relations. Please go ahead.

Stephane Aka

Good morning, and thank you for joining us on APA Corporation's Third Quarter 2026 Financial and Operational Results Conference Call.

We will begin the call with an overview by CEO, John Christmann. Ben Rodgers, CFO, will share further color on our results and outlook. Steve Riney, President; and Tracey Henderson, Executive Vice President of Exploration, are also on the call and available to answer questions.

We will start with prepared remarks and allocate the remainder of time to Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our financial and operational supplement, which can be found on our Investor Relations website at investor.apacorp.com.

Please note that we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website. Consistent with previous reporting practices, adjusted production numbers cited in today's call are adjusted to exclude noncontrolling interest in Egypt and Egypt tax barrels.

I'd like to remind everyone that today's discussion will contain forward-looking estimates and assumptions based on our current views and reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discuss on today's call. A full disclaimer is located with the supplemental information on our website.

And with that, I will turn the call over to John.

John Christmann

Good morning, and thank you for joining us. Today, I will review our third quarter results, discuss our fourth quarter outlook and outline our preliminary plans for 2027.

APA's strategy is anchored by 3 priorities: delivering top-tier operational performance, building a high-quality portfolio and maintaining financial discipline. Together with our long-term commitment to oil and gas, these core principles guide our investments, operations and capital returns framework. By honing these priorities over the past 2 years, we are continuing to strengthen our operating capabilities, resulting in another quarter of excellent performance. More efficient development programs, a structurally lower cost base, and higher commodity prices are driving stronger free cash flow.

In addition, the carry agreement under our joint venture in Suriname further enhances our financial flexibility, allowing us to fund only 10% of GranMorgu's development capital while retaining our 40% working interest and significant exposure to the project's future cash flows. This has enabled us to advance this world-class opportunity while reducing debt, returning cash to shareholders and building the long-term future of the company.

Turning to the third quarter. We delivered strong performance across our core assets. U.S. oil production again exceeded guidance. Egypt sustained gross BOE production, and GranMorgu continues to progress toward first oil in mid-2028. Capital investment in the Permian and Egypt, as well as total operating costs, were in line with guidance. We generated approximately $700 million in free cash flow and returned over $500 million to shareholders through dividends and buybacks. We also took additional steps to strengthen the balance sheet, which Ben will discuss shortly.

In the U.S., oil production of 128,000 barrels per day exceeded our guidance through a combination of high uptime, earlier turn-in-lines and robust new well performance. Total U.S. production averaged 294,000 BOEs per day, also above guidance. Our focus remains on improving capital productivity through continued drilling and completion efficiency gains and maintaining reliable base production. In Egypt, gross production was relatively flat quarter-over-quarter at 206,000 BOEs per day. Gross gas production of 542 million cubic feet per day exceeded our guidance, driven by strong well performance and more resilient base production. Average gas realizations increased to $4.34 per Mcf from $4.23 in the second quarter. Adjusted production was approximately 64,000 BOEs per day, slightly below guidance due to PSC impacts, primarily from higher oil prices.

In Suriname, our partner, Total, continues to advance GranMorgu on budget and on schedule for first oil in mid-2028. Third quarter development capital was approximately $40 million, which was below our guidance. A portion of capital shifted into the fourth quarter, primarily due to the timing of equipment deliveries and rig upgrades, but our full year outlook remains unchanged.

Shifting to our fourth quarter and updated full year outlook. In the Permian, drilling and completion efficiency gains continue to improve capital productivity. These improvements have driven an increase in full year U.S. oil production guidance to 124,000 barrels per day, above our initial guidance of 120,000 to 122,000 barrels per day. Faster drilling cycle times are also enabling us to accelerate some frac activity into the fourth quarter, resulting in a modest increase in 2026 capital spending that will support a smoother production profile entering 2027.

Fourth quarter oil production is expected to moderate with the timing of turn-in-lines during the year and reflecting seasonal weather impacts. In Egypt, we expect gross BOE production to increase slightly for the fourth quarter and full year. Across the portfolio, our priorities remain operational execution, continued cost management, and strong free cash flow generation as we close out 2026.

Looking ahead to 2027, we will continue generating significant free cash flow from our core producing assets while advancing GranMorgu towards first oil. The strength of our core business provides the financial flexibility to further enhance the balance sheet and return capital to shareholders while pursuing several high-impact exploration opportunities. Our preliminary estimate for upstream capital next year is approximately $2.5 billion. Exploration and GranMorgu development account for roughly 60% of the increase from 2026, with the remainder driven by Permian activity and modest inflation. We expect this investment program to result in similar U.S. and Egypt production year-over-year.

In the Permian, activity will increase relative to 2026 with a greater percentage in the Delaware Basin, while Egypt activity and capital allocation across oil and gas will remain consistent with 2026. GranMorgu investment will increase as development drilling begins. On the exploration side, capital investment will return to our targeted range of 10% to 15% of annual upstream capital. These investments across our differentiated portfolio could establish new sources of long-term production, free cash flow, and substantial value for shareholders beyond our existing development assets. In Suriname, 2 exploration wells are planned with our partner, Total, targeting additional resource potential to extend GranMorgu's production plateau or even support a second development. In Alaska, this winter's program includes one exploration well and an appraisal test of our Sockeye discovery. In Uruguay, we expect to spud our OFF-6 well with Eni in late 2027. We will provide a more detailed outlook in February.

In closing, our third quarter results demonstrate continued execution across the portfolio. Our Permian and Egypt businesses are delivering reliable performance and significant free cash flow, enhanced by a structurally lower cost base and improved capital efficiency. This foundation, combined with our advantageous joint venture in Suriname, puts APA in a unique strategic position. Our carry agreement with Total significantly reduces our upfront capital outlay for GranMorgu while preserving our ownership interest and full share of future profit allocations. As a result, we are able to advance a material high-impact exploration program while reducing debt and returning significant capital to shareholders. Few companies have the financial flexibility to fund world-class growth opportunities of this scale while strengthening their balance sheet and delivering significant shareholder returns. We are accomplishing all of these priorities simultaneously with GranMorgu less than 2 years from first oil and a transformational increase in free cash flow on the horizon.

With that, I'll turn the call over to Ben.

Ben Rodgers

Thank you, John. For the third quarter, APA reported net income attributable to common stock of $698 million or $2 per diluted common share. Consistent with prior periods, these results include items outside of core earnings. The largest after-tax adjustment was an unrealized derivative gain of $17 million. Excluding this and other smaller items, adjusted net income was $676 million or $1.94 per diluted common share. We generated $699 million of free cash flow, bringing our year-to-date total to more than $1.9 billion. These results reflect strong execution across our core assets and the benefits of structural cost improvements and capital efficiencies achieved over the past 2 years. Building on this performance, higher expected production in the U.S. and Egypt and stronger commodity prices have increased our 2026 free cash flow outlook to $2.9 billion, up $600 million from August. This supports significant returns to shareholders and continued debt reduction through year-end.

We accelerated the pace of capital returns during the quarter, repurchasing 10.5 million shares at an average price of $42.78 for approximately $450 million. Including $87 million of dividends, we returned $537 million to shareholders. Through October, we've repurchased $762 million of shares this year, reducing our outstanding share count by approximately 5% since year-end 2025. At current strip pricing, we expect approximately $650 million of additional share repurchases by year-end. Together with dividends, these repurchases are consistent with our commitment to return at least 60% of annual free cash flow to shareholders.

We also retired approximately $450 million of debt during the third quarter, opportunistically repurchasing bonds across near-term and longer-dated maturities. We ended the quarter with total debt of $3.3 billion and net debt of $3.2 billion. Our debt reduction since year-end 2024 has lowered annualized interest expense by more than $180 million compared with 2024. G&A expense for the quarter was $112 million, including $56 million of stock-based compensation, primarily due to the increase in our share price.

Turning to capital. Third quarter upstream investment was $466 million, approximately $30 million below guidance, mostly due to GranMorgu spending that shifted into the fourth quarter. For our 2026 capital outlook, we have increased full year upstream capital guidance by $30 million to $2.1 billion, reflecting the additional Permian activity John mentioned. Separately, we've reduced full year ARO spending by $15 million, reflecting the deferral of certain North Sea activities as we optimize the program. This partially offsets the cash flow impact of the higher upstream capital spending. We've increased full year LOE guidance by $25 million, primarily due to higher stock-based compensation expense allocated to LOE. Underlying operating cost performance remains strong with savings across our asset base absorbing $40 million of higher diesel costs in Egypt this year.

Moving to our gas trading portfolio, which has been a significant cash flow contributor for several years and represents a differentiated financial advantage for APA. While contributions will vary with market conditions, we expect the portfolio to continue generating substantial free cash flow. At current strip pricing and inclusive of basis hedges, we expect approximately $1.1 billion in pretax cash flow this year and $950 million next year.

As we close out the year, I'd like to put our cost reduction progress over the last 2 years into perspective. When we launched this initiative in early 2025, we targeted $350 million in annualized savings by the end of 2027. We achieved that milestone 2 years ahead of schedule and subsequently increased our target to $500 million, which we expect to reach by the end of this year. Combined with the $180 million in annualized interest savings already in place, reaching our year-end target would bring total annualized savings to approximately $680 million compared with our cost structure as we exited 2024. For context, that is equivalent to roughly 80% of APA's total free cash flow in 2024.

These improvements span our entire business from greater capital efficiency and lower operating costs to a simpler, more efficient organization. The result is a structurally lower cost base that improves investment returns and supports more resilient free cash flow through commodity cycles. Our employees deserve tremendous credit for these results. Their commitment to finding better ways to operate has translated directly into tangible value for shareholders.

Looking ahead to 2027, our focus is on sustaining these gains and driving further reductions as we navigate industry-wide inflationary pressures. On capital, our preliminary outlook for the Permian program John described already incorporates mid-single-digit cost inflation. We are pursuing additional efficiencies from increased Delaware Basin activity and other initiatives that could help offset those pressures. These potential capital savings are not reflected in our outlook. On operating costs, projects implemented in both Egypt and the Permian are already lowering LOE with more savings to come in 2027. In Egypt, we are expanding power projects to reduce diesel consumption and operating costs. In the Permian, we will benefit from a full year of savings from projects implemented this year alongside new initiatives to drive further reductions.

Strong free cash flow and continued cost discipline also position us to take the next step in strengthening our balance sheet. We are approaching our $3 billion net debt target and expect to achieve it in the near future. Looking beyond this milestone, we are establishing a new net debt target of $2 billion. Further debt reduction will lower interest expense and fixed cash obligations, supporting free cash flow through commodity cycles. It also preserves flexibility to fund future developments from exploration success while continuing to return at least 60% of annual free cash flow to shareholders.

In closing, our financial progress this year is translating into meaningful shareholder value. With $2.9 billion of expected free cash flow, we are funding significant share repurchases while strengthening our balance sheet. We expect to achieve our $3 billion net debt target about 1.5 years after announcing it, positioning us to establish a new target from a stronger financial foundation. Our cost savings progress across operations and overhead has been central to these results. Sustaining these gains and building on them remains a priority as we look ahead. Over the next 5 years, we see a compelling opportunity to grow free cash flow per share through sustained cost discipline, lower interest expense, GranMorgu start-up and continued share repurchases. Importantly, this growth does not depend on additional exploration success, which would provide further upside.

With that, I will turn the call over to the operator for Q&A.

Operator

[Operator Instructions] Our first question comes from Doug Leggate with Wolfe Research.

ช่วงถาม-ตอบ

Douglas George Blyth Leggate

I wonder if I could touch first on exploration and then specifically in Alaska. I know Tracey is on the call, so I don't know if you want to defer to her maybe. But my question is specifically related to the King Street well that you drilled some time ago. And my understanding is there was a deeper target and a shallower formation that you -- that may have helped derisk part of the Chinook target that you're going to drill early next year. I just wonder if you could confirm that or characterize how you see the risk profile of Chinook? That's my first question.

And my follow-up is just, obviously, you're generating an enormous amount of free cash flow. Credit to Steve for being unhedged perhaps. But I wonder where does the ARO, the abandonment liability stack up in the seriatim of priorities for that cash flow between buybacks, debt reduction, and so on? And I'll leave it there.

John Christmann

Thank you, Doug. I'll jump in and then let Tracey add any color to exploration, and then I'll let Ben take the ARO question.

But we're excited about what we have in the Lagniappe play in Alaska. We've really derisked the play with 2 discoveries. King Street was the first that really confirmed a working petroleum system and high-quality reservoir, and that was really, really important. Sockeye was the second well, and we drilled it next. It was not our largest feature, but it was the one that we had the best seismic data over at the time. And what Sockeye did was really tie our interpretations to the seismic and the geologic model to the actual well results. And so both of those wells are very, very important for the whole Lagniappe area. We've got plans next year to appraise Sockeye with the Hungry Horse well and then test a larger separate feature with Chinook.

I'll let Tracey comment a little bit more on Chinook.

Tracey Henderson

Yes. I'll just comment a little bit specifically on your question, Doug, regarding the King Street well and what we had reported previously on that. I think what I would say is it was very encouraging. We saw an accumulation at depth that we reported. And as you mentioned, some shallower things that looked encouraging as well. I think we really need to get the well down at Chinook. I would say it's encouraging that we see a lot of hydrocarbons in these Alaska wells and some that are roughly in the same stratigraphic zones, but I think it's -- we're basically interpolating a bit too much to say that there's a direct connection or derisking of Chinook based on the seismic from what we see. But it is encouraging to see hydrocarbons in those age-equivalent zones that gives us some confidence that going into Chinook that we feel pretty good about it.

John Christmann

Ben, on the ARO?

Ben Rodgers

Sure. So just on your second question, Doug, yes, we obviously have the ARO liability in the North Sea and the contingent liability in the Gulf of America that we're managing. Hats off to the teams. They've done a great job in the past years in Gulf of America and decommissioning those assets. And we just started decommissioning this year in the North Sea, and that will continue for years to come. When you look at what we've done on the balance sheet, you can see from our maturity profile, we've got less than $200 million due in the next 9 years. And that gives us flexibility, not only from a shareholder return and funding exploration and other items, but also allows us flexibility to flex up or down based on commodity cycles for how we decommission those assets with that being really the only liability we have to manage.

This year, it's pretty close to $300 million. I would expect the same next year, and dollars in that ZIP code are going to be very manageable for us as we're continuing to execute on those plans. When you look at our leverage stats, we talk a lot about debt to EBITDA. At the end of this year, we're looking at close to 0.4x. But even when you include that liability at the end of this year, it's close to 3/4 turn leverage, and that is significantly different than the past here at Apache. And so we think we're well positioned. We're focused on lowering total liabilities, including the ARO. Those are long term. The team is doing a good job of derisking that, and total debt coming down definitely helps, too.

Operator

Our next question comes from John Freeman with Raymond James.

John Freeman

You currently got four rigs running in Midland and one in Delaware. John, you mentioned that the plan is for Delaware activity to increase next year. So I assume we should take that sixth rig that gets added and assume that goes to the Delaware next year, so kind of a 4-2 kind of split next year in the Permian?

John Christmann

You're going to see us, John, like we said, add back. We've been fortunate this year that due to the heavy TIL count in the back half of '25 and the DUCs. We were able to get down to 4 rigs this year. Next year, we will be adding back in. This year, we were kind of in the 85%, 15% ratio of Midland to Delaware. Longer term, it's more 60-40, but you'll see us probably more in the 2/3, 1/3, but we'll give you more specifics in February.

Steve, anything you want to add?

Stephen Riney

Yes. Just to be clear, right now, we have three rigs running in Midland, one running in Delaware, and right around the beginning of the turn of the year from '26 to '27, we'll be adding two more rigs. But as John said, it's 85-15 for the current year, and over the next few years, we'll be migrating to what is reflected in our economic inventory that we talked about in February, which is 60% Midland Basin and 40% Delaware Basin, we'll eventually get to that type of a ratio.

John Freeman

Got it. And then just following up, Ben, on your comments on the balance sheet. Obviously, leverage is in great shape. You've got the new long-term net debt target of $2 billion. And just want to kind of think about how we should be sort of kind of modeling this because when I look at the kind of the debt stack, there's very little left, obviously, on the '29, those will be gone soon. And then after that, you don't really have any near-term maturities. It's pretty low coupon, and none of that is really able to get called at par at least for a number of years. And so I'm just trying to think about when you think net debt target, should we just assume that maybe in the near term that outside the '29 that a lot of it is just building cash? Or just sort of how to think about that net debt target?

Ben Rodgers

Sure. So stepping back just on the target itself, in August of last year, we outlined the $3 billion, and we said strip pricing, we'd expect to achieve that in 3 to 4 years. And obviously, over the last 18 months, we've experienced higher than strip pricing, and we're able to achieve that milestone here likely by the end of this year. So when you look at this new $2 billion target, similar timing at mid-cycle pricing, it's likely by the end of the decade. And if higher prices play out, then again, we could achieve that in a much shorter time period.

So we'll continue to be opportunistic, John, as we look at the debt stack. There's -- it's a pretty strong benefit that we have that $2.8 billion of debt is past the 2040 time frame. There are some other 2030 bonds that we could potentially go after. A lot of that longer-dated debt, just given the current interest rate environment, is trading below par. So you get a little bit additional deleveraging, but definitely recognize that, that's also a benefit to have 17 years average maturity there.

So we'll be balanced and thoughtful on that. Obviously, for our shareholders, it doesn't make a lot of sense to sit on hundreds of millions of dollars of cash for a long period of time. It's meant to be a guiding star as we continue to develop our assets, continue to explore, and return capital to shareholders. So we'll be balanced. We've done a lot of cleanup on the balance sheet so far. And it's really just meant to be a guiding star for us as we continue in the next few years. And from an actual what bonds we go after, we'll be very thoughtful about that as we think about maturities and refinancing risk, et cetera.

Operator

Our next question comes from Arun Jayaram with JPMorgan Securities.

Arun Jayaram

I wanted to see, John, if you could elaborate a little bit more on your Suriname exploration plans for 2027 with Total. Maybe elaborate on what you plan to do with the drill bit outside of outside of GranMorgu.

John Christmann

Sure. Suriname, if you go back to when we announced the Krabdagu appraisal wells at the time that I said that those Krabdagu wells did more than just appraise Krabdagu. They actually derisked an entire exploration fairway and tied it back to our seismic. You'll see in our supplement, Slide 19, we put out a map. It's actually a map that Total has also used and put out. We've outlined kind of four wells over the next 2 years that we'll start back with. They are very similar to what we've done at Krabdagu and Sapakara. So we're very excited about them. I do believe them derisked. I'll also point out that they will be wells that are drilled within the current development area, so they will be cost recoverable under the existing project.

But most importantly, they provide the potential at a minimum to extend the plateau, but we also believe you move on these early because you want to understand the materiality and the potential for possible additional infrastructure, either a second boat or possibly even the ability we're in water depths where you could set some fixed structures and get creative on what you might be able to do with the infrastructure. So I think it's important that you get after them early because it gives you some clues on what you might be able to do with it versus if they were only going to be plateau extenders and you'd be more inclined to drill them later in the life cycle. But we're very, very excited. It's something that is relatively derisked, and it's something that both us and our partner are excited to get after because they're definitely going to add more resource.

Arun Jayaram

Got it. And I'll stay with the exploration theme. I know you and your partner, Eni, in Uruguay have contracted a deepwater floater to drill that well with Noble in the fourth quarter. Could you talk a little bit about the prospect that you plan to drill in 4Q of next year? And how -- and maybe a little bit more around your thoughts around exploration in Uruguay.

John Christmann

Yes, Arun, we have entered into a contract with Noble for the BlackHawk. It's a block now that we'll hold 60% and Eni will hold 40%. They're going to cover most of the well costs.

And I've got Tracey here. So I'll let Tracey high level, talk about kind of what we're going after with Eni in our OFF-6 block in Uruguay.

Tracey Henderson

Sure, John. It is basically deepwater depositional system in the Cretaceous that's worked in multiple places around the Cretaceous margin on the Atlantic margins, most notably Namibia, which is our analog for this and the conjugate margin. So it is a really a petroleum systems test on the Latin American side for what has worked on the African margin. The prospect itself, as I said, is very much like a lot of the deepwater Cretaceous turbidite depositional systems that we've seen that have worked in large scale in other parts around the circum-Atlantic. So big well, but we are excited to get it down and very happy to have Eni in as a partner.

Operator

Our next question comes from Neal Dingmann with William Blair.

Neal Dingmann

John, my first question is on -- for maybe, you, Steve, on the gas trading, specifically. Could you speak to what we might expect next year with what I would call your 3 buckets there with Cheniere, the contract, and the FT given certainly what looks like to be a volatile commodity market.

John Christmann

Yes, Neal, I'll have Ben jump in on this one.

Ben Rodgers

Sure. So yes, strip pricing from last week, which is -- which we do for every earnings we said it the week before. At strip pricing as we look for next year across LNG, Waha, NYMEX and Houston Ship Channel, that gas trading portfolio is going to generate about $950 million of pretax cash flow. Current prices, they continue to move around. I'd say it's probably in the mid- to high 8s now. So still a significant contributor there. What you see is that this year, obviously, a lot coming from the pipelines. And then LNG, they were more balanced, just kind of given how the curve is next year. The Permian FT portion has shrunk, and that's expected. You've seen a lot of new pipelines, not only be FID-ed recently, but also coming on this year, and that's going to continue into early next year.

So you're seeing Waha strengthen. But the Gulf Coast prices are still pretty low compared to global LNG prices. So still expect that to continue next year just given some of the global infrastructure damage that's done through the conflict in the Middle East. So just stepping back, it's been a very, very differentiated source of cash flow for us. If you look through this year alone, that business has generated $2.5 billion. So you look at adding next year, you're going to be over $3 billion from that book of business for us. So it's differentiated. It goes into our shareholder returns, and we expect that to continue for many years.

Neal Dingmann

Perfect. And then my second question just on Egypt. John, just given going on in the Middle East, it appears you've been spared and it doesn't seem like there's been any issues there. So again, I guess, first question, do you think that will continue to be the case? And then secondly, just maybe talk about workover activity there. It seems like you've been able to keep production very stable. Just if you could address that.

John Christmann

Neal, 2 good questions. I would say, first in Egypt, they've been a long-term peacemaker over there and have done a really good job in difficult time periods. We've seen that over the last couple of years, starting with Gaza and now what's happening here and now things have moved into the Red Sea. But Egypt has done a great job. We continue to be in very, very close contact with both the Egyptian government and the U.S. Embassy. And obviously, the -- our highest priority is the safety and well-being of our employees over there. But things continue to be something we keep a close eye on, but Egypt has done a really, really admirable job thus far. And I would expect that to continue, but it's something we watch very, very closely.

Steve, anything you want to comment on the workovers?

Stephen Riney

Yes. Neal, you might remember a few years ago, we had an issue with some mounting workover backlog in Egypt. And we ended up with about 20 workover rigs running in Egypt back then. Since that time, we've concentrated quite a bit of activity around increasing workover rig efficiency and making sure that we're getting after the workover opportunities as quickly as possible. Just recently, we're currently running 23% more jobs per workover rig than we have in the recent past. So we've gotten really quite good at this. At any point in time, we'll be running today between 15 and 20 workover rigs in Egypt. And that backlog has been worked down to a pretty small number now.

So workover activity in Egypt is a really important part of what we call base resilience, which is just keeping the base running as efficiently and as effectively as possible.

John Christmann

The last thing I'll add on Egypt there, Neal, is we got current last September on our PDRs, and they've done a really good job of staying current. And so it's been a real good situation. We've been bringing on gas, which has been helping them. They're importing and buying LNG. And so that's been a big deal. And then, of course, they got current with the rest of the industry in June of this year. So I really applaud them for doing a really, really good job in a difficult time period.

Operator

Our next question comes from Chris Baker with Evercore.

Christopher Baker

I wanted to follow up on the '27 outlook. I think, Ben, you mentioned that further efficiency gains are not part of the initial look that you all have outlined today. I'm just curious to the extent that you do see some of those efficiency gains continue and offset some of the cost pressures, we're likely to see that show up in terms of lower capital or perhaps higher volumes?

Ben Rodgers

Sure. Yes, I just -- we've made so much progress over the past 2 years across the company in all 3 buckets that we've talked about on controllable spend with capital, LOE and G&A. On the capital side, a lot of that progress has been in the Permian and concentrated this year in the Midland Basin and the ability to park rigs over DSUs and have them just really work drives lower drilling days and a lot of different efficiencies, and that's even beyond other development design and other changes that the team has implemented, and we've done all of that with higher production. So hats off to the team there.

The main takeaway is, as John and Steve alluded to earlier, higher increase in the Delaware Basin. We've made progress on certain wells there, but we just don't have as many at-bats in the Delaware, and that will increase next year. And we'll see how many of those learnings from the Midland Basin can be carried over to the Delaware Basin from an efficiency standpoint on both drilling and completions and even through to equipping and facilities. So we think that there's upside there. We didn't include that right now. I just want to make sure that we get over there and get some wells down in the Delaware, and we'll update folks as we continue throughout next year.

Christopher Baker

Great. And then just as a follow-up, you mentioned some projects around driving continued cost savings in LOE. I'm just curious in terms of any split you can offer between what you've locked in with projects this year versus new initiatives that could potentially show up as further benefits for 2027.

Stephen Riney

Yes, Chris, this is Steve. So we did announce at the beginning of the year, we had about $100 million of what we call LOE projects. And that's probably doesn't do justice to the projects because they also include benefits in reliability and runtime and uptime. So it actually shows up both in LOE reduction, but also in production efficiency and production resilience as we call it. That $100 million was being spent -- it's primarily -- it's in the Permian Basin. It's primarily around things like ESP conversion to gas lift, more efficient gas treatment, primarily through larger scale gas treatment and facility consolidation type of projects. So these are brownfield types of projects.

That $100 million worth of projects, we said would save about $40 million of LOE on a run rate basis. We're delivering those projects on time and as expected in terms of the anticipated results. There will be more of those projects. The budget for 2027 does include some, not as much as $100 million, but a meaningful amount of projects. And I would say that, that's still a preliminary budget for 2027. There are things that we can do even beyond 2027 on the facility side. Most of it is -- most of the type of stuff, as you can imagine, would be done in front of the drilling rigs. And so we're not going to go out and do work that we don't need to do because we're not drilling in a certain area.

Operator

Our next question comes from Michael Scialla with Stephens.

Michael Scialla

I wanted to ask about the debt. You're getting your net debt down to your target of $3 billion. Ben, you mentioned the low leverage. Can you talk about the decision to lower that net debt target further to $2 billion rather than changing your free cash flow framework?

Ben Rodgers

Sure. We're thoughtful across our capital returns and our debt balance. One of the things that we take into consideration is obviously funding our exploration program, but we've got a differentiated free cash flow inflection coming from GranMorgu in '28, and that continues through the end of the decade. And we look at that and understand we need to continue to delever the balance sheet so that we can be more opportunistic in debt funding potential growth opportunities and believe that instead of being defensive on our debt balance now, we can be more on the offensive as opportunities arise, and that will be accretive to shareholders over the long term.

So we take that into consideration, but just realize we need to continue to pay down debt as we have the different priorities that we're managing across development capital, exploration capital, continuing to get after our decommissioning assets and lower debt is going to really just make Apache stronger over the long term and give us a lot of options as we look even beyond 2028 with additional free cash flow from GranMorgu. So set us up well. We didn't want to plant a flag and say we're done. So continued work there. But it's not going to come at the cost of anything else across the priorities that the company has.

Michael Scialla

Makes sense. Appreciate that, Ben. I wanted to follow up on Alaska. Looking at the appraisal well you have planned for Sockeye, it strikes me that it's pretty good distance away from the discovery well, I think like 8 miles. That seems like a pretty large step out. And you mentioned that Chinook is potentially larger than Sockeye. So I'm just thinking about the resource here. I don't want to pin you down on any number, but it looks like obviously a large potential resource. And I'm wondering how you're thinking longer term if you do have success here with the 50% working interest. Are you comfortable maintaining that? Or would you look to bring a partner like you did in Suriname?

John Christmann

Yes, Mike, I mean, when we announced the Sockeye discovery, we said it was a stratigraphic feature that was 25,000 to 30,000 acres. Now clearly, we're stepping out a pretty good distance from that with Hungry Horse, and it is -- I think it's over 6 miles as a crow flies. It's something we're very excited about. It looks fantastic. We did reprocess the seismic data last year. And one thing we did learn is that we did not drill Sockeye initially in the thickest part. That's something that the seismic told us. So we are anxious to appraise it with Hungry Horse. It is a pretty big step-out appraisal well. And then we do have a very large prospect in Chinook that we're also very excited about.

There's tremendous resource up here. We think 50% is a good starting point for us today. With the Savant acquisition that we have on queue, it kind of brings us some starter kit things that we can work with a pipeline, a big gravel pad, there's a dock, there's a runway, a lot of things, and we're going to have a lot of flexibility. But we want to get these 2 wells down and come back after that. But I think we like having the 50% where we sit today is a good place for us to be.

Operator

Next question comes from Charles Meade with Johnson Rice.

Charles Meade

Tracey, I want to start by saying circum-Atlantic, that's a new word for me, but I think I understand what it means. John, if I could actually go back to the earlier question around the exploration in Suriname. If I understood you correctly, I think what I inferred from that is that these other prospects that you and Total plan on drilling are similar and maybe similar age and similar settings to Krabdagu as opposed to a different or new kind of play type. And I'm wondering if I'm understanding that correctly. And then also, all other things being equal, which, of course, they're not, but it looks like the most interesting one to drill would be that one to the west of Sapakara, where it looks like you could test 2 different prospects with one wellbore. But I wonder if you could just comment on my interpretation there.

John Christmann

No. I mean I'd say it is exactly similar reservoirs, right, same play, same age rock. Actually, while Sapakara is really one primary zone, Krabdagu actually has multiple targets, and we've been clear on that. We do see multiple targets to the west there of Sapakara. But as I've said, these are very, very similar to what we already understand and are part of the development plan for GranMorgu.

So anything you want to add, Tracey?

Tracey Henderson

No, I think, John, that's spot on. We do see -- as John mentioned, like in Krabdagu, multiple locations where we've got more than one zone that's hydrocarbon bearing. And so I don't think that's going to be uncommon as we continue to drill these out.

Operator

Our next question comes from Bob Brackett with Bernstein Research.

Bob Brackett

Staying with the theme of Suriname. You mentioned interestingly on the Q&A that the prospects you're targeting are ring-fenced within the development license. Does that mean that if you did pursue a second development that, that development could access the cost oil pool from the existing operations and therefore, be fairly capital efficient?

John Christmann

Bob, I'll just say they're inside the existing bucket, right? So yes, I mean -- but...

Bob Brackett

Okay. Interesting. The other question I might have is, typically, in a PSC such as this when there's an exploration phase and you'll relinquish parts of the block that you deem nonprospective over time. And I'm thinking back to Bonboni, for example. When you chose these prospects, have you relinquished other parts of the block that you deem nonprospective? Or is there a chance to go out and look at a different system or a play idea?

John Christmann

I mean at this point, we have not relinquished any of 58. In 53, we relinquished everything, except for the little corner that we've got mapped there around Baja. But those are -- we've still got some time and some work to do with Staatsolie in terms of Block 58. I think we'll be able to keep a big piece of this for quite a while. But there are some things in the future where we do have procedures in place that we have to work through with Staatsolie.

Operator

Our next question comes from Leo Mariani with ROTH.

Leo Mariani

I wanted to follow up quickly here on Alaska. Obviously, you got some wells drilling over the winter. Just wanted to kind of get a sense of like, is there sort of a minimum success case in terms of maybe a couple of hundred million barrels or something like that, that you need to kind of be comfortable with to proceed with development? Anything you can kind of do to help us out would be great there.

John Christmann

Yes, Leo, it's a great question. I'll just say it's early. We announced the discovery well, the 2 wells, but Sockeye, we have not come back and started talking about what we would need in an FID case or anything at that point, at this time. So we want to appraise Sockeye first, get Chinook down and then when we're ready to come back and talk about some things, we can give more color and more detail there.

Leo Mariani

Okay. And then just in the U.S., obviously, you're doing a little bit more shifting of activity towards the Delaware. It sounds like next year. Just trying to get a sense, is some of that just driven by the fact that you've had such strong gains on efficiency in the Midland that you believe you can probably replicate some of that in the Delaware, which maybe makes it kind of more competitive?

And then secondly, do you still think there's kind of wood to chop on efficiency gains overall in the Permian?

John Christmann

I mean I think there's definitely wood to chop. We keep staying after it. I think it's more just a function of our portfolio and the prospectivity over time. What we've tried to do is efficiently develop resource. We made great progress in the Midland. We've also made good progress in the Delaware. But when you just look at our inventory longer term, post Callon, we picked up a lot of potential. We've got a lot of shallow zones, a lot that's in our technical inventory bucket to be moved over. And so our natural progression with what our acreage footprint today is would be more of a 60-40 split, and you just see us shifting slightly to that. So it's just kind of the natural progression of our program. But definitely see -- as Ben outlined well, we see room for more efficiencies in the Delaware like we've been able to extract in the Midland.

Operator

Our next question comes from the line of Noah Hungness with Wells Fargo.

Noah Hungness

I just have one quick one here. And it was on your comment there, John, about derisking some of the technical upside locations in the Permian. When we're thinking about your program next year and in a success case, how could we think about the amount of inventory that you guys could derisk in your '27 program?

John Christmann

Yes. No, I mean, we came out in February with a good look at both our -- what we'll call our development inventory and then our technical locations. At some point, we'll come out with another refresh of that. That's something we're constantly working on. We're always testing things. We have what locations as we're consuming inventory in a year. We're also testing things and moving things over. And we'll come back at some point and give an update and a fresh look on that. But we are constantly appraising and industry is also appraising. We have a lot of HBP acreage. So there is a progression there that has taken place this year. There's more taking place now, and we'll come back and update that. We'll figure out the appropriate cadence, but we rolled that all out in February of earlier this year.

Operator

This concludes the question-and-answer session. I'd like to turn the call back over to John Christmann, CEO, for closing remarks.

John Christmann

Thank you. In closing, I will leave you with the following thoughts. First, we continue to deliver strong operational and financial performance, supporting substantial shareholder returns and debt reduction in 2026. Second, improving capital efficiency and ongoing cost savings are enhancing the long-term durability of our core assets in the Permian and Egypt. Lastly, with GranMorgu less than 2 years from start-up, we have a clear path to a step change in production and free cash flow through the end of the decade and beyond. Combined with our world-class exploration portfolio, we are very well positioned to deliver differentiated long-term shareholder value. Thank you.

Operator

Thank you for your participation. You may now disconnect. Good day.