[6-K] YPF Sociedad Anonima Current Report (Foreign Issuer)
YPF 2Q25 highlights: Revenue rose 0.7% QoQ to US$4.64 bn but fell 6% YoY as Brent-linked prices weakened. Adjusted EBITDA slipped 9.7% QoQ to US$1.12 bn; net profit rebounded to US$58 mn from a US$10 mn loss in 1Q25 yet remained 89% below 2Q24. Cash-flow & leverage: Free cash flow was –US$365 mn, an improvement versus –US$957 mn in 1Q25. Net debt increased 6% QoQ to US$8.83 bn, pushing leverage to 1.9× LTM EBITDA (1Q25: 1.8×). Liquidity (cash + ST investments) fell to US$1.01 bn.
Operations: Total production held at 546 kboe/d (–1% QoQ); shale oil accounted for 59% of oil output. Lifting cost dropped 19% QoQ to US$12.3/boe (core-hub shale: US$4.9/boe). Refinery utilization eased to 89% due to La Plata maintenance; domestic fuel volumes gained 4%. CAPEX remained high at US$1.16 bn (71% unconventional).
Strategic moves: • Signed US$2 bn project-finance loan for 25%-owned VMOS export pipeline (23% complete). • Agreed to buy 45% stakes in La Escalonada & Rincón La Ceniza for US$500 mn. • LNG JV (SESA) took FID on second floating train, lifting committed capacity to 5.95 MTPA. • Moody’s upgraded corporate rating to B2 after sovereign upgrade.
Key pressures: lower crude & fuel prices, refinery downtime and higher net debt offset cost efficiencies and gas-season gains. Guidance reaffirmed focus on Vaca Muerta growth and conventional divestitures.
Punti salienti YPF 2Q25: Il fatturato è aumentato dello 0,7% rispetto al trimestre precedente, raggiungendo 4,64 miliardi di dollari, ma è diminuito del 6% su base annua a causa del calo dei prezzi legati al Brent. L'EBITDA rettificato è sceso del 9,7% QoQ a 1,12 miliardi di dollari; l'utile netto è tornato positivo a 58 milioni di dollari dopo una perdita di 10 milioni nel 1Q25, ma resta comunque l'89% inferiore rispetto al 2Q24. Flussi di cassa e leva finanziaria: Il flusso di cassa libero è stato negativo per 365 milioni di dollari, un miglioramento rispetto ai -957 milioni del 1Q25. Il debito netto è aumentato del 6% QoQ a 8,83 miliardi di dollari, portando la leva finanziaria a 1,9× EBITDA degli ultimi 12 mesi (1Q25: 1,8×). La liquidità (cassa + investimenti a breve termine) è scesa a 1,01 miliardi di dollari.
Operazioni: La produzione totale si è mantenuta a 546 kboe/giorno (-1% QoQ); il petrolio da scisto rappresentava il 59% della produzione totale di petrolio. Il costo di estrazione è diminuito del 19% QoQ a 12,3 dollari/boe (core-hub shale: 4,9 dollari/boe). L'utilizzo delle raffinerie è sceso all'89% a causa della manutenzione di La Plata; i volumi di carburante domestico sono aumentati del 4%. Gli investimenti in conto capitale sono rimasti elevati a 1,16 miliardi di dollari (71% nel settore non convenzionale).
Mosse strategiche: • Firmato un prestito di project finance da 2 miliardi di dollari per il gasdotto di esportazione VMOS, di cui YPF detiene il 25% (completamento al 23%). • Accordo per l'acquisto del 45% delle partecipazioni in La Escalonada e Rincón La Ceniza per 500 milioni di dollari. • La joint venture LNG (SESA) ha preso la decisione finale di investimento per il secondo treno galleggiante, portando la capacità impegnata a 5,95 MTPA. • Moody’s ha migliorato il rating aziendale a B2 dopo l’upgrade sovrano.
Pressioni principali: Prezzi più bassi del greggio e dei carburanti, fermo impianti di raffinazione e aumento del debito netto hanno compensato le efficienze di costo e i guadagni nella stagione del gas. Le previsioni confermano l’attenzione sulla crescita di Vaca Muerta e sulle dismissioni nel settore convenzionale.
Aspectos destacados de YPF 2T25: Los ingresos aumentaron un 0,7% trimestralmente hasta US$4.64 mil millones, pero cayeron un 6% interanual debido a la debilidad de los precios vinculados al Brent. El EBITDA ajustado bajó un 9,7% trimestralmente a US$1.12 mil millones; la utilidad neta se recuperó a US$58 millones desde una pérdida de US$10 millones en el 1T25, aunque sigue un 89% por debajo del 2T24. Flujo de caja y apalancamiento: El flujo de caja libre fue negativo en US$365 millones, mejorando respecto a los -US$957 millones del 1T25. La deuda neta aumentó un 6% trimestralmente a US$8.83 mil millones, elevando el apalancamiento a 1,9× EBITDA de los últimos 12 meses (1T25: 1,8×). La liquidez (efectivo + inversiones a corto plazo) cayó a US$1.01 mil millones.
Operaciones: La producción total se mantuvo en 546 kboe/día (-1% trimestral); el petróleo de esquisto representó el 59% de la producción petrolera. El costo de extracción bajó un 19% trimestral a US$12.3/boe (núcleo shale: US$4.9/boe). La utilización de refinerías bajó al 89% debido al mantenimiento en La Plata; los volúmenes de combustible doméstico aumentaron un 4%. El CAPEX se mantuvo alto en US$1.16 mil millones (71% no convencional).
Movimientos estratégicos: • Firmó un préstamo de financiamiento de proyectos por US$2 mil millones para el gasoducto de exportación VMOS, con una participación del 25% (23% completado). • Acuerdo para comprar participaciones del 45% en La Escalonada y Rincón La Ceniza por US$500 millones. • La JV de GNL (SESA) tomó la decisión final de inversión para el segundo tren flotante, aumentando la capacidad comprometida a 5.95 MTPA. • Moody’s mejoró la calificación corporativa a B2 tras la mejora soberana.
Presiones clave: Precios más bajos del crudo y combustible, paradas en refinerías y mayor deuda neta contrarrestaron las eficiencias de costos y ganancias en la temporada de gas. La guía reafirma el enfoque en el crecimiento de Vaca Muerta y desinversiones en convencionales.
YPF 2분기 25년 주요 내용: 매출은 전분기 대비 0.7% 증가한 46.4억 달러였으나, 브렌트 유가 약세로 전년 동기 대비 6% 감소했습니다. 조정 EBITDA는 전분기 대비 9.7% 감소한 11.2억 달러였으며, 순이익은 1분기 25년 1,000만 달러 손실에서 5,800만 달러 흑자로 반등했으나 2분기 24년 대비 89% 낮은 수준입니다. 현금 흐름 및 레버리지: 자유 현금 흐름은 -3.65억 달러로 1분기 25년 -9.57억 달러에서 개선되었습니다. 순부채는 전분기 대비 6% 증가한 88.3억 달러로, 레버리지는 최근 12개월 EBITDA 기준 1.9배로 상승(1분기 25년: 1.8배)했습니다. 유동성(현금 + 단기 투자)은 10.1억 달러로 감소했습니다.
운영 현황: 총 생산량은 54.6만 boe/일로 전분기 대비 1% 감소했으며, 셰일 오일이 전체 석유 생산의 59%를 차지했습니다. 생산 비용은 전분기 대비 19% 하락한 배럴당 12.3달러였고(핵심 셰일 허브: 배럴당 4.9달러), 라플라타 정유공장 유지보수로 정유시설 가동률은 89%로 하락했으나 국내 연료 판매량은 4% 증가했습니다. CAPEX는 11.6억 달러로 높게 유지되었으며, 이 중 71%는 비전통 부문에 투자되었습니다.
전략적 움직임: • 25% 지분을 보유한 VMOS 수출 파이프라인을 위한 20억 달러 프로젝트 파이낸싱 대출 체결(진행률 23%). • La Escalonada 및 Rincón La Ceniza 지분 45%를 5억 달러에 인수 합의. • LNG 합작회사(SESA)는 두 번째 플로팅 트레인에 대한 최종 투자 결정을 내려 약정 용량을 595만 톤으로 확대. • 무디스가 주권 등급 상향 후 기업 신용등급을 B2로 상향 조정.
주요 압박 요인: 원유 및 연료 가격 하락, 정유공장 가동 중단, 순부채 증가가 비용 효율성과 가스 시즌 이익을 상쇄했습니다. 가이던스는 Vaca Muerta 성장과 전통 자산 매각에 중점을 두고 있음을 재확인했습니다.
Faits marquants YPF 2T25 : Le chiffre d'affaires a augmenté de 0,7 % d'un trimestre à l'autre pour atteindre 4,64 milliards de dollars, mais a diminué de 6 % en glissement annuel en raison de la faiblesse des prix liés au Brent. L'EBITDA ajusté a reculé de 9,7 % en un trimestre, à 1,12 milliard de dollars ; le bénéfice net est repassé à 58 millions de dollars après une perte de 10 millions au 1T25, mais reste inférieur de 89 % au 2T24. Flux de trésorerie et endettement : Le flux de trésorerie disponible était de –365 millions de dollars, une amélioration par rapport à –957 millions au 1T25. La dette nette a augmenté de 6 % d'un trimestre à l'autre pour atteindre 8,83 milliards de dollars, portant le levier à 1,9× l’EBITDA des 12 derniers mois (1T25 : 1,8×). La liquidité (trésorerie + placements à court terme) est tombée à 1,01 milliard de dollars.
Opérations : La production totale est restée stable à 546 kboe/jour (–1 % d’un trimestre à l’autre) ; le pétrole de schiste représentait 59 % de la production pétrolière. Le coût d’extraction a diminué de 19 % en un trimestre à 12,3 $/boe (noyau schiste : 4,9 $/boe). L’utilisation des raffineries a diminué à 89 % en raison de la maintenance de La Plata ; les volumes de carburants domestiques ont augmenté de 4 %. Les CAPEX sont restés élevés à 1,16 milliard de dollars (71 % non conventionnels).
Mouvements stratégiques : • Signature d’un prêt de financement de projet de 2 milliards de dollars pour le gazoduc d’exportation VMOS détenu à 25 % (23 % achevé). • Accord pour l’achat de participations de 45 % dans La Escalonada et Rincón La Ceniza pour 500 millions de dollars. • La coentreprise GNL (SESA) a pris la décision finale d’investissement pour le deuxième train flottant, portant la capacité engagée à 5,95 MTPA. • Moody’s a relevé la note de l’entreprise à B2 après la revalorisation souveraine.
Principales pressions : La baisse des prix du brut et des carburants, les arrêts de raffinerie et l’augmentation de la dette nette ont compensé les gains d’efficacité et les bénéfices de la saison gazière. Les prévisions confirment l’accent mis sur la croissance de Vaca Muerta et les cessions conventionnelles.
YPF 2Q25 Highlights: Der Umsatz stieg im Quartalsvergleich um 0,7 % auf 4,64 Mrd. USD, fiel jedoch im Jahresvergleich um 6 %, da Brent-gebundene Preise nachgaben. Das bereinigte EBITDA sank im Quartalsvergleich um 9,7 % auf 1,12 Mrd. USD; der Nettogewinn erholte sich auf 58 Mio. USD von einem Verlust von 10 Mio. USD im 1Q25, blieb jedoch 89 % unter dem Niveau des 2Q24. Cashflow & Verschuldung: Der freie Cashflow betrug –365 Mio. USD, eine Verbesserung gegenüber –957 Mio. USD im 1Q25. Die Nettoverschuldung stieg im Quartalsvergleich um 6 % auf 8,83 Mrd. USD, wodurch die Verschuldungsquote auf das 1,9-fache des LTM EBITDA anstieg (1Q25: 1,8×). Die Liquidität (Barmittel + kurzfristige Investitionen) sank auf 1,01 Mrd. USD.
Operationen: Die Gesamtproduktion blieb mit 546 kboe/Tag nahezu konstant (–1 % QoQ); Schieferöl machte 59 % der Ölproduktion aus. Die Förderkosten sanken im Quartalsvergleich um 19 % auf 12,3 USD/boe (Kern-Schiefer: 4,9 USD/boe). Die Raffinerieauslastung sank aufgrund von Wartungsarbeiten in La Plata auf 89 %; die inländischen Kraftstoffmengen stiegen um 4 %. Die Investitionsausgaben blieben mit 1,16 Mrd. USD hoch (71 % unkonventionell).
Strategische Maßnahmen: • Unterzeichnung eines 2-Milliarden-USD-Projektfinanzierungskredits für die 25%-Beteiligung an der VMOS-Exportpipeline (23 % fertiggestellt). • Vereinbarung zum Kauf von 45%-Anteilen an La Escalonada und Rincón La Ceniza für 500 Mio. USD. • LNG-Joint-Venture (SESA) traf die endgültige Investitionsentscheidung für die zweite schwimmende Anlage und erhöhte die zugesagte Kapazität auf 5,95 MTPA. • Moody’s hob das Unternehmensrating nach dem Sovereign-Upgrade auf B2 an.
Wesentliche Belastungen: Niedrigere Rohöl- und Kraftstoffpreise, Raffinerieausfälle und höhere Nettoverschuldung kompensierten Kosteneffizienzen und Gas-Saison-Gewinne. Die Prognose bekräftigt den Fokus auf das Wachstum in Vaca Muerta und konventionelle Desinvestitionen.
- Lifting cost down 19% QoQ to US$12.3/boe, enhancing upstream margins despite price headwinds.
- Net profit returned to black at US$58 mn versus prior-quarter loss.
- US$2 bn project-finance secured for VMOS export pipeline, de-risking a key growth conduit.
- Moody’s credit upgrade to B2 improves funding outlook.
- Shale now 59% of oil output, aligning with strategic shift to Vaca Muerta.
- Adjusted EBITDA fell 10% QoQ and 7% YoY due to lower crude and fuel prices.
- Free cash flow negative US$365 mn; cash balance down 18% QoQ.
- Net debt climbed 6% QoQ, leverage up to 1.9×.
- Refinery utilization dropped 5 pp on maintenance; domestic fuel prices fell 8% QoQ in USD.
- Net income down 89% YoY, showing sensitivity to commodity prices.
Insights
TL;DR: Mixed quarter—cost wins and project progress offset by softer pricing and rising leverage.
Revenue stability hides margin compression: a 12% fall in realised oil price and weaker domestic fuel pricing drove a 10% QoQ EBITDA drop. Yet lifting costs fell sharply thanks to mature-field exits, preserving Upstream EBITDA (flat QoQ). Seasonal gas sales cushioned the blow. Strategically, US$2 bn financing for the VMOS pipeline and the LNG FID de-risk export optionality, while the US$500 mn block buy deepens future shale oil runway. However, free cash flow is still negative and leverage ticked up to 1.9×; sustained Brent weakness or peso inflation could stress cash generation.
TL;DR: Liquidity shrank but debt markets remain open; leverage manageable at sub-2×.
Net debt rose US$497 mn as cash burned and new local bonds funded capex. Interest coverage remains adequate (LTM EBITDA/interest ≈5×) and 2H25 maturities of US$793 mn look serviceable with current liquidity plus operating cash flow. The Moody’s upgrade to B2 and successful local market taps (US$761 mn since 2Q close) underscore access to funding. Watchpoints: sustained negative FCF, inventory price swings and execution risk on VMOS capex.
Punti salienti YPF 2Q25: Il fatturato è aumentato dello 0,7% rispetto al trimestre precedente, raggiungendo 4,64 miliardi di dollari, ma è diminuito del 6% su base annua a causa del calo dei prezzi legati al Brent. L'EBITDA rettificato è sceso del 9,7% QoQ a 1,12 miliardi di dollari; l'utile netto è tornato positivo a 58 milioni di dollari dopo una perdita di 10 milioni nel 1Q25, ma resta comunque l'89% inferiore rispetto al 2Q24. Flussi di cassa e leva finanziaria: Il flusso di cassa libero è stato negativo per 365 milioni di dollari, un miglioramento rispetto ai -957 milioni del 1Q25. Il debito netto è aumentato del 6% QoQ a 8,83 miliardi di dollari, portando la leva finanziaria a 1,9× EBITDA degli ultimi 12 mesi (1Q25: 1,8×). La liquidità (cassa + investimenti a breve termine) è scesa a 1,01 miliardi di dollari.
Operazioni: La produzione totale si è mantenuta a 546 kboe/giorno (-1% QoQ); il petrolio da scisto rappresentava il 59% della produzione totale di petrolio. Il costo di estrazione è diminuito del 19% QoQ a 12,3 dollari/boe (core-hub shale: 4,9 dollari/boe). L'utilizzo delle raffinerie è sceso all'89% a causa della manutenzione di La Plata; i volumi di carburante domestico sono aumentati del 4%. Gli investimenti in conto capitale sono rimasti elevati a 1,16 miliardi di dollari (71% nel settore non convenzionale).
Mosse strategiche: • Firmato un prestito di project finance da 2 miliardi di dollari per il gasdotto di esportazione VMOS, di cui YPF detiene il 25% (completamento al 23%). • Accordo per l'acquisto del 45% delle partecipazioni in La Escalonada e Rincón La Ceniza per 500 milioni di dollari. • La joint venture LNG (SESA) ha preso la decisione finale di investimento per il secondo treno galleggiante, portando la capacità impegnata a 5,95 MTPA. • Moody’s ha migliorato il rating aziendale a B2 dopo l’upgrade sovrano.
Pressioni principali: Prezzi più bassi del greggio e dei carburanti, fermo impianti di raffinazione e aumento del debito netto hanno compensato le efficienze di costo e i guadagni nella stagione del gas. Le previsioni confermano l’attenzione sulla crescita di Vaca Muerta e sulle dismissioni nel settore convenzionale.
Aspectos destacados de YPF 2T25: Los ingresos aumentaron un 0,7% trimestralmente hasta US$4.64 mil millones, pero cayeron un 6% interanual debido a la debilidad de los precios vinculados al Brent. El EBITDA ajustado bajó un 9,7% trimestralmente a US$1.12 mil millones; la utilidad neta se recuperó a US$58 millones desde una pérdida de US$10 millones en el 1T25, aunque sigue un 89% por debajo del 2T24. Flujo de caja y apalancamiento: El flujo de caja libre fue negativo en US$365 millones, mejorando respecto a los -US$957 millones del 1T25. La deuda neta aumentó un 6% trimestralmente a US$8.83 mil millones, elevando el apalancamiento a 1,9× EBITDA de los últimos 12 meses (1T25: 1,8×). La liquidez (efectivo + inversiones a corto plazo) cayó a US$1.01 mil millones.
Operaciones: La producción total se mantuvo en 546 kboe/día (-1% trimestral); el petróleo de esquisto representó el 59% de la producción petrolera. El costo de extracción bajó un 19% trimestral a US$12.3/boe (núcleo shale: US$4.9/boe). La utilización de refinerías bajó al 89% debido al mantenimiento en La Plata; los volúmenes de combustible doméstico aumentaron un 4%. El CAPEX se mantuvo alto en US$1.16 mil millones (71% no convencional).
Movimientos estratégicos: • Firmó un préstamo de financiamiento de proyectos por US$2 mil millones para el gasoducto de exportación VMOS, con una participación del 25% (23% completado). • Acuerdo para comprar participaciones del 45% en La Escalonada y Rincón La Ceniza por US$500 millones. • La JV de GNL (SESA) tomó la decisión final de inversión para el segundo tren flotante, aumentando la capacidad comprometida a 5.95 MTPA. • Moody’s mejoró la calificación corporativa a B2 tras la mejora soberana.
Presiones clave: Precios más bajos del crudo y combustible, paradas en refinerías y mayor deuda neta contrarrestaron las eficiencias de costos y ganancias en la temporada de gas. La guía reafirma el enfoque en el crecimiento de Vaca Muerta y desinversiones en convencionales.
YPF 2분기 25년 주요 내용: 매출은 전분기 대비 0.7% 증가한 46.4억 달러였으나, 브렌트 유가 약세로 전년 동기 대비 6% 감소했습니다. 조정 EBITDA는 전분기 대비 9.7% 감소한 11.2억 달러였으며, 순이익은 1분기 25년 1,000만 달러 손실에서 5,800만 달러 흑자로 반등했으나 2분기 24년 대비 89% 낮은 수준입니다. 현금 흐름 및 레버리지: 자유 현금 흐름은 -3.65억 달러로 1분기 25년 -9.57억 달러에서 개선되었습니다. 순부채는 전분기 대비 6% 증가한 88.3억 달러로, 레버리지는 최근 12개월 EBITDA 기준 1.9배로 상승(1분기 25년: 1.8배)했습니다. 유동성(현금 + 단기 투자)은 10.1억 달러로 감소했습니다.
운영 현황: 총 생산량은 54.6만 boe/일로 전분기 대비 1% 감소했으며, 셰일 오일이 전체 석유 생산의 59%를 차지했습니다. 생산 비용은 전분기 대비 19% 하락한 배럴당 12.3달러였고(핵심 셰일 허브: 배럴당 4.9달러), 라플라타 정유공장 유지보수로 정유시설 가동률은 89%로 하락했으나 국내 연료 판매량은 4% 증가했습니다. CAPEX는 11.6억 달러로 높게 유지되었으며, 이 중 71%는 비전통 부문에 투자되었습니다.
전략적 움직임: • 25% 지분을 보유한 VMOS 수출 파이프라인을 위한 20억 달러 프로젝트 파이낸싱 대출 체결(진행률 23%). • La Escalonada 및 Rincón La Ceniza 지분 45%를 5억 달러에 인수 합의. • LNG 합작회사(SESA)는 두 번째 플로팅 트레인에 대한 최종 투자 결정을 내려 약정 용량을 595만 톤으로 확대. • 무디스가 주권 등급 상향 후 기업 신용등급을 B2로 상향 조정.
주요 압박 요인: 원유 및 연료 가격 하락, 정유공장 가동 중단, 순부채 증가가 비용 효율성과 가스 시즌 이익을 상쇄했습니다. 가이던스는 Vaca Muerta 성장과 전통 자산 매각에 중점을 두고 있음을 재확인했습니다.
Faits marquants YPF 2T25 : Le chiffre d'affaires a augmenté de 0,7 % d'un trimestre à l'autre pour atteindre 4,64 milliards de dollars, mais a diminué de 6 % en glissement annuel en raison de la faiblesse des prix liés au Brent. L'EBITDA ajusté a reculé de 9,7 % en un trimestre, à 1,12 milliard de dollars ; le bénéfice net est repassé à 58 millions de dollars après une perte de 10 millions au 1T25, mais reste inférieur de 89 % au 2T24. Flux de trésorerie et endettement : Le flux de trésorerie disponible était de –365 millions de dollars, une amélioration par rapport à –957 millions au 1T25. La dette nette a augmenté de 6 % d'un trimestre à l'autre pour atteindre 8,83 milliards de dollars, portant le levier à 1,9× l’EBITDA des 12 derniers mois (1T25 : 1,8×). La liquidité (trésorerie + placements à court terme) est tombée à 1,01 milliard de dollars.
Opérations : La production totale est restée stable à 546 kboe/jour (–1 % d’un trimestre à l’autre) ; le pétrole de schiste représentait 59 % de la production pétrolière. Le coût d’extraction a diminué de 19 % en un trimestre à 12,3 $/boe (noyau schiste : 4,9 $/boe). L’utilisation des raffineries a diminué à 89 % en raison de la maintenance de La Plata ; les volumes de carburants domestiques ont augmenté de 4 %. Les CAPEX sont restés élevés à 1,16 milliard de dollars (71 % non conventionnels).
Mouvements stratégiques : • Signature d’un prêt de financement de projet de 2 milliards de dollars pour le gazoduc d’exportation VMOS détenu à 25 % (23 % achevé). • Accord pour l’achat de participations de 45 % dans La Escalonada et Rincón La Ceniza pour 500 millions de dollars. • La coentreprise GNL (SESA) a pris la décision finale d’investissement pour le deuxième train flottant, portant la capacité engagée à 5,95 MTPA. • Moody’s a relevé la note de l’entreprise à B2 après la revalorisation souveraine.
Principales pressions : La baisse des prix du brut et des carburants, les arrêts de raffinerie et l’augmentation de la dette nette ont compensé les gains d’efficacité et les bénéfices de la saison gazière. Les prévisions confirment l’accent mis sur la croissance de Vaca Muerta et les cessions conventionnelles.
YPF 2Q25 Highlights: Der Umsatz stieg im Quartalsvergleich um 0,7 % auf 4,64 Mrd. USD, fiel jedoch im Jahresvergleich um 6 %, da Brent-gebundene Preise nachgaben. Das bereinigte EBITDA sank im Quartalsvergleich um 9,7 % auf 1,12 Mrd. USD; der Nettogewinn erholte sich auf 58 Mio. USD von einem Verlust von 10 Mio. USD im 1Q25, blieb jedoch 89 % unter dem Niveau des 2Q24. Cashflow & Verschuldung: Der freie Cashflow betrug –365 Mio. USD, eine Verbesserung gegenüber –957 Mio. USD im 1Q25. Die Nettoverschuldung stieg im Quartalsvergleich um 6 % auf 8,83 Mrd. USD, wodurch die Verschuldungsquote auf das 1,9-fache des LTM EBITDA anstieg (1Q25: 1,8×). Die Liquidität (Barmittel + kurzfristige Investitionen) sank auf 1,01 Mrd. USD.
Operationen: Die Gesamtproduktion blieb mit 546 kboe/Tag nahezu konstant (–1 % QoQ); Schieferöl machte 59 % der Ölproduktion aus. Die Förderkosten sanken im Quartalsvergleich um 19 % auf 12,3 USD/boe (Kern-Schiefer: 4,9 USD/boe). Die Raffinerieauslastung sank aufgrund von Wartungsarbeiten in La Plata auf 89 %; die inländischen Kraftstoffmengen stiegen um 4 %. Die Investitionsausgaben blieben mit 1,16 Mrd. USD hoch (71 % unkonventionell).
Strategische Maßnahmen: • Unterzeichnung eines 2-Milliarden-USD-Projektfinanzierungskredits für die 25%-Beteiligung an der VMOS-Exportpipeline (23 % fertiggestellt). • Vereinbarung zum Kauf von 45%-Anteilen an La Escalonada und Rincón La Ceniza für 500 Mio. USD. • LNG-Joint-Venture (SESA) traf die endgültige Investitionsentscheidung für die zweite schwimmende Anlage und erhöhte die zugesagte Kapazität auf 5,95 MTPA. • Moody’s hob das Unternehmensrating nach dem Sovereign-Upgrade auf B2 an.
Wesentliche Belastungen: Niedrigere Rohöl- und Kraftstoffpreise, Raffinerieausfälle und höhere Nettoverschuldung kompensierten Kosteneffizienzen und Gas-Saison-Gewinne. Die Prognose bekräftigt den Fokus auf das Wachstum in Vaca Muerta und konventionelle Desinvestitionen.
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 6-K
REPORT OF FOREIGN PRIVATE ISSUER
PURSUANT TO RULE 13A-16 OR 15D-16
UNDER THE SECURITIES EXCHANGE ACT OF 1934
For the month of August 2025
Commission File Number: 001-12102
YPF Sociedad Anónima
(Exact name of registrant as specified in its charter)
Macacha Güemes 515
C1106BKK Buenos Aires, Argentina
(Address of principal executive office)
Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:
Form 20-F ☒ Form 40-F ☐
YPF Sociedad Anónima
TABLE OF CONTENT
ITEM 1 Translation of letter to the Argentine Securities Commission dated August 7, 2025.
2Q25 Webcast on Aug 8, 2025 9:00 am ET / 10:00 am BAT CLICK HERE INVESTOR RELATIONS CENTER IR TEAM hp s://investors.ypf.com MARGARITA CHUN –IR MANAGER Inversoresypf@ypf.com VALENTINA LPEZ –IR CHRISTIAN GONZLEZ –IR
MAIN HIGHLIGHTS OF 2Q25
| KPI |
2Q25 | 1Q25 | Q/Q Δ | 2Q24 | Y/Y Δ | 1H25 | 1H24 | Δ | ||||||||||||||||||||||||
| Financial |
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| Revenues |
4,641 | 4,608 | 1 | % | 4,935 | -6 | % | 9,249 | 9,245 | 0 | % | |||||||||||||||||||||
| Adjusted EBITDA |
1,124 | 1,245 | -10 | % | 1,204 | -7 | % | 2,369 | 2,449 | -3 | % | |||||||||||||||||||||
| Net Result |
58 | (10 | ) | N/A | 535 | -89 | % | 48 | 1,192 | -96 | % | |||||||||||||||||||||
| CAPEX |
1,160 | 1,214 | -5 | % | 1,200 | -3 | % | 2,374 | 2,369 | 0 | % | |||||||||||||||||||||
| FCF |
(365 | ) | (957 | ) | -62 | % | (257 | ) | 42 | % | (1,322 | ) | (651 | ) | 103 | % | ||||||||||||||||
| Net Debt |
8,833 | 8,336 | 6 | % | 7,457 | 18 | % | 8,833 | 7,457 | 18 | % | |||||||||||||||||||||
| Net Leverage Ratio (x) |
1.9 | 1.8 | 8 | % | 1.7 | 15 | % | 1.9 | 1.7 | 15 | % | |||||||||||||||||||||
| Upstream |
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| Hydrocarbon Production (Kboe/d) |
545.7 | 552.1 | -1 | % | 539.0 | 1 | % | 548.9 | 532.5 | 3 | % | |||||||||||||||||||||
| Crude Oil (Kbbl/d) |
247.9 | 269.9 | -8 | % | 248.8 | 0 | % | 258.8 | 252.1 | 3 | % | |||||||||||||||||||||
| Natural Gas (Mm3/d) |
39.7 | 37.3 | 6 | % | 38.8 | 2 | % | 38.5 | 37.6 | 3 | % | |||||||||||||||||||||
| NGL (Kbbl/d) |
48.0 | 47.3 | 2 | % | 46.1 | 4 | % | 47.7 | 43.9 | 8 | % | |||||||||||||||||||||
| Crude Oil Price (US$/bbl) |
59.5 | 67.9 | -12 | % | 70.8 | -16 | % | 63.9 | 69.5 | -8 | % | |||||||||||||||||||||
| Natural Gas Price (US$/MBTU) |
4.1 | 3.0 | 38 | % | 4.0 | 2 | % | 3.5 | 3.5 | 0 | % | |||||||||||||||||||||
| Crude Oil Exports (Kbbl/d) |
43.6 | 36.4 | 20 | % | 30.4 | 43 | % | 40.0 | 28.8 | 39 | % | |||||||||||||||||||||
| Shale Oil Production (Kbbl/d) |
145.1 | 147.3 | -1 | % | 113.3 | 28 | % | 146.2 | 112.8 | 30 | % | |||||||||||||||||||||
| Total Lifting Cost (US$/boe) |
12.3 | 15.3 | -19 | % | 16.2 | -24 | % | 13.8 | 14.6 | -5 | % | |||||||||||||||||||||
| Core-Hub Lifting Cost (US$/boe) |
4.9 | 4.6 | 7 | % | 4.7 | 5 | % | 4.8 | 4.0 | 20 | % | |||||||||||||||||||||
| Midstream & Dw |
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| Crude Processed (Kbbl/d) |
301.4 | 318.0 | -5 | % | 299.2 | 1 | % | 309.6 | 300.1 | 3 | % | |||||||||||||||||||||
| Refineries’ Utilization Rate (%) |
89 | % | 94 | % | -5 | % | 89 | % | 1 | % | 92 | % | 89 | % | 3 | % | ||||||||||||||||
| Local Fuels Volume Sold (Km3) |
3,532 | 3,405 | 4 | % | 3,431 | 3 | % | 6,937 | 6,920 | 0 | % | |||||||||||||||||||||
| Local Fuels Net Price (US$/m3) |
641 | 697 | -8 | % | 711 | -10 | % | 697 | 701 | -1 | % | |||||||||||||||||||||
| Imported Fuels (Km3) |
95 | 78 | 22 | % | — | N/A | 173 | 142 | 22 | % | ||||||||||||||||||||||
| R&M Adj. EBITDA (US$/bbl) |
11.9 | 14.3 | -17 | % | 11.4 | 4 | % | 14.3 | 14.9 | -4 | % | |||||||||||||||||||||
In US$ million, unless noted otherwise. EBITDA = Operating income + Depreciation of PP&E + Depreciation of the right of use assets + Amortization of intangible assets + Unproductive exploratory drillings + (Reversal) / Deterioration of PP&E. Adjusted EBITDA = EBITDA that excludes IFRS 16 effects +/- one-off items. Net Leverage Ratio = Net Debt / LTM Adj. EBITDA. FCF = Cash flow from Operations less CAPEX (Investing activities), M&A (Investing activities), and interest and leasing payments (Financing activities). Fuels = diesel + gasoline. R&M is refining and marketing business, it excludes petrochemicals and agro products.
Adj. EBITDA totaled US$1,124 million (-10% q/q), primarily explained by Brent contraction, which affected prices of local fuels and other refined products, besides value of inventories (but also lower unit costs of oil purchases to third parties), and to a minor extent, decreased working interest in Aguada del Chañar shale oil block (100%®51%) since Apr-25. These effects were partially offset by lower lifting costs on the back of reduced exposure to mature fields, and peak winter sales of natural gas.
The -7% y/y adj. EBITDA was also mostly due to lower price of fuels, partially offset by shale expansions and even better conventional lifting cost. Also, 2Q24 was affected by severe weather in Patagonia.
Excluding mature fields, 2Q25 proxy adj. EBITDA would have been US$1,250 million.
CAPEX was US$1,160 million (-5% q/q & -3% y/y). 71% of the CAPEX was unconventional (mostly shale), reinforcing the focus on the development of Vaca Muerta.
Shale oil production averaged 145 kbbl/d (-1% q/q and +28% y/y), representing 59% of our total oil production (1Q25: 55% and 2Q24: 46%). Even after reducing stake in Aguada del Chañar, the ramp-up in La Angostura Sur I (South-Hub) led the sequential stable level. Moreover, in line with our 4x4 Plan, recently we executed a binding agreement to acquire 45% working interest of La Escalonada and Rincón La Ceniza blocks (located in the most promising area in the oil and wet gas windows of North Vaca Muerta) from Total Austral S.A. for US$500 million, subject to certain conditions and adjustments.
Oil exports reached 44 kbbl/d, being +20% q/q due to exceptional Escalante heavy oil exports (La Plata refinery under programmed maintenance), while +43% y/y was also driven by shale oil expansion.
Progress on our main projects:
| • | Conventional Exit Program, since the last earnings release, we achieved remarkable progress: |
| • | Andes Phase I: (28 blocks: 24 divested & 4 in final stage) we transferred 6 blocks in Mendoza South Cluster, 4 blocks in Neuquén North Cluster and 3 blocks in Neuquén South Cluster. We also advanced to a final stage in 4 blocks: 3 blocks in Chubut Non-Operated Cluster and 1 block in Señal Picada – Punta Barda Cluster. |
| • | Mature Fields reversal: (20 blocks: 11 reverted & 9 in progress) we reverted 10 blocks in Santa Cruz Cluster and 1 block in Restinga Alí Cluster (Province of Chubut) |
| • | Andes Phase II: (new) we launched a new round, adding 16 new conventional performing blocks, 6 in Salta, 8 in Mendoza, 1 in Río Negro and 1 in Chubut. It is worth highlighting the outstanding tertiary recovery production in Manantiales Behr (Chubut) and Chachahuen (Mendoza) Clusters. |
| • | VMOS oil export pipeline (~550 kbbl/d by 1H27, ~US$3 billion CAPEX, YPF stake: ~25%): the SPV signed a syndicated loan for US$2 billion at SOFR+5.5% in Jul-25 to finance ~70% of the CAPEX, reopening Project Finance in Argentina. Construction progress: 23% (Jul-25), it completed welding works of ~120 km (Allen – 1° pumping station). |
Page 2/14
| • | Argentina LNG: Phase 3 (~12 MTPA) signed in Jun-25 Heads Agreement with ENI, the strategic partner. Also, in Aug-25, SESA (YPF 25% equity stake), the SPV for Argentina LNG 1, obtained the FID approval for a 20-year bareboat charter agreement of the second vessel, MK II (3.5 MTPA, COD expected by 2028), and considering the first vessel (2.45 MTPA, COD expected by 2027), total capacity amounts to 5.95 MTPA. |
Buenos Aires, Aug 7, 2025 – YPF (BYMA: YPFD | NYSE: YPF1). Information based on financial statements (FS) prepared according to IFRS in force in Argentina. The sum of the parts of certain figures is subject to rounding. The Company’s functional currency is US$.
1. ANALYSIS OF CONSOLIDATED RESULTS OF 2Q25
| Consolidated Revenues Breakdown Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Diesel |
1,526 | 1,521 | 1,672 | 0.4 | % | -8.7 | % | 3,047 | 3,227 | -5.6 | % | |||||||||||||||||||||
| Gasoline |
923 | 1,037 | 946 | -10.9 | % | -2.4 | % | 1,960 | 1,968 | -0.4 | % | |||||||||||||||||||||
| Natural gas as producers (third parties) |
447 | 306 | 419 | 45.9 | % | 6.6 | % | 753 | 697 | 8.0 | % | |||||||||||||||||||||
| Other |
1,025 | 988 | 1,160 | 3.8 | % | -11.6 | % | 2,014 | 1,951 | 3.2 | % | |||||||||||||||||||||
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| Total Domestic Market |
3,922 | 3,852 | 4,197 | 1.8 | % | -6.6 | % | 7,774 | 7,844 | -0.9 | % | |||||||||||||||||||||
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| Jet fuel |
73 | 94 | 120 | -22.7 | % | -39.3 | % | 167 | 274 | -39.1 | % | |||||||||||||||||||||
| Grain and flours |
172 | 133 | 130 | 28.8 | % | 32.4 | % | 305 | 157 | 94.4 | % | |||||||||||||||||||||
| Crude oil |
254 | 240 | 226 | 5.7 | % | 12.1 | % | 494 | 415 | 18.9 | % | |||||||||||||||||||||
| Petchem & Other |
221 | 289 | 262 | -23.4 | % | -15.6 | % | 510 | 556 | -8.3 | % | |||||||||||||||||||||
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| Total Export Market |
719 | 756 | 738 | -4.9 | % | -2.5 | % | 1,475 | 1,401 | 5.2 | % | |||||||||||||||||||||
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| Total Revenues |
4,641 | 4,608 | 4,935 | 0.7 | % | -6.0 | % | 9,249 | 9,245 | 0.0 | % | |||||||||||||||||||||
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Net Revenues amounted to US$4,641 million (+1% q/q), mainly derived from peak seasonal gas and diesel oil demand, in addition to increased exports of oil (especially Escalante) and grain and flour (encouraged by lower export duties). These effects were partially offset by Brent contraction impact in our refined products, particularly local fuels, as well as off-peak gasoline demand.
| Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Lifting cost |
(611 | ) | (758 | ) | (793 | ) | -19.3 | % | -22.9 | % | (1,369 | ) | (1,410 | ) | -2.9 | % | ||||||||||||||||
| Other Upstream |
(157 | ) | (147 | ) | (162 | ) | 6.9 | % | -2.9 | % | (304 | ) | (274 | ) | 11.2 | % | ||||||||||||||||
| OPEX Downstream |
(527 | ) | (535 | ) | (559 | ) | -1.4 | % | -5.6 | % | (1,062 | ) | (997 | ) | 6.5 | % | ||||||||||||||||
| Otros Midstream & Downstream |
(71 | ) | (55 | ) | (57 | ) | 28.3 | % | 24.3 | % | (126 | ) | (105 | ) | 20.3 | % | ||||||||||||||||
| LNG & IG, New Energies, Corp. & Other |
(162 | ) | (249 | ) | (271 | ) | -34.9 | % | -40.1 | % | (411 | ) | (435 | ) | -5.5 | % | ||||||||||||||||
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| Total OPEX |
(1,529 | ) | (1,744 | ) | (1,842 | ) | -12.3 | % | -17.0 | % | (3,273 | ) | (3,222 | ) | 1.6 | % | ||||||||||||||||
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| Depreciation & Amortization |
(788 | ) | (806 | ) | (638 | ) | -2.2 | % | 23.5 | % | (1,594 | ) | (1,290 | ) | 23.6 | % | ||||||||||||||||
| Royalties |
(243 | ) | (265 | ) | (282 | ) | -8.5 | % | -13.8 | % | (508 | ) | (540 | ) | -5.8 | % | ||||||||||||||||
| Other costs |
(312 | ) | (319 | ) | (383 | ) | -2.0 | % | -18.5 | % | (631 | ) | (655 | ) | -3.7 | % | ||||||||||||||||
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| Total Other Costs |
(1,343 | ) | (1,390 | ) | (1,303 | ) | -3.4 | % | 3.1 | % | (2,733 | ) | (2,485 | ) | 10.0 | % | ||||||||||||||||
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| Fuels imports (including jet fuel) |
(53 | ) | (59 | ) | 0 | -10.1 | % | N/A | (112 | ) | (99 | ) | 13.2 | % | ||||||||||||||||||
| Crude oil purchases to third parties |
(442 | ) | (485 | ) | (469 | ) | -9.0 | % | -5.9 | % | (927 | ) | (844 | ) | 9.9 | % | ||||||||||||||||
| Biofuel purchases |
(244 | ) | (226 | ) | (224 | ) | 8.2 | % | 9.2 | % | (470 | ) | (465 | ) | 1.0 | % | ||||||||||||||||
| Agro products purchases |
(224 | ) | (119 | ) | (190 | ) | 88.4 | % | 17.6 | % | (342 | ) | (261 | ) | 31.3 | % | ||||||||||||||||
| Other purchases |
(246 | ) | (139 | ) | (302 | ) | 76.2 | % | -18.7 | % | (385 | ) | (480 | ) | -19.7 | % | ||||||||||||||||
| Stock variations |
(132 | ) | 69 | (2 | ) | N/A | 6500.0 | % | (63 | ) | (127 | ) | -50.4 | % | ||||||||||||||||||
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| Total Purchases & Stock Variations |
(1,340 | ) | (959 | ) | (1,187 | ) | 39.7 | % | 12.9 | % | (2,299 | ) | (2,275 | ) | 1.1 | % | ||||||||||||||||
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| Other operating results, net |
(26 | ) | (323 | ) | (8 | ) | -92.0 | % | 225.0 | % | (349 | ) | (2 | ) | 17350.0 | % | ||||||||||||||||
| Reversal / (Impairment) of PP&E |
9 | — | (5 | ) | N/A | N/A | 9 | (5 | ) | N/A | ||||||||||||||||||||||
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| Operating Costs + Purchases + Impairment of Assets |
(4,229 | ) | (4,416 | ) | (4,345 | ) | -4.2 | % | -2.7 | % | (8,645 | ) | (7,989 | ) | 8.2 | % | ||||||||||||||||
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Stock variations include price effects by (US$ 96) million in 2Q25, US$5 million for 1Q25, US$12 million for 2Q24, (US$91) million for 1H25 and (US$157) million for 1H24
OPEX totaled US$1,529 million (-12% q/q), mainly derived from savings associated with reduced exposure to mature fields and lower OPEX from the remaining fields. Total Other Costs reached US$1,343 million (-3% q/q), mostly explained by lower royalties (oil price contraction and lower conventional production, partially compensated by peak winter sales of gas), as well as decreased depreciation and amortizations in the upstream.
Purchases & Stock Variations amounted to US$1,340 million (+40% q/q). Purchases increased q/q, driven by peak seasonal agriproducts and natural gas purchases, partially offset by lower crude oil purchases to third parties (as a result of lower unit cost related to Brent contraction). Stock variations reached a negative US$132 million in 2Q25 (compared to a positive US$69 million in 1Q25), primarily explained by reduced prices which resulted in a lower replacement cost of our inventories.
| 1 | 1 ADR = 1 share. Total issued capital stock amounted to 393,312,793 shares as of June-2025 (51% Argentina Government; 29% NYSE and 20% ByMA). |
Page 3/14
Other operating net results totaled negative US$26 million (vs. a loss of US$323 million in 1Q25), mainly due to one-off items related to mature fields in 1Q25, and to a minor extent, positive results from revaluation of companies and sale of 49% of Aguada del Chañar block in 2Q25.
| Consolidated Net Income Breakdown Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Operating income / (loss) |
412 | 192 | 590 | 114.6 | % | -30.2 | % | 604 | 1,256 | -51.9 | % | |||||||||||||||||||||
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| Result from equity interests in associates and joint ventures |
(6 | ) | 81 | 27 | N/A | N/A | 75 | 156 | -51.9 | % | ||||||||||||||||||||||
| Financial results, net |
(287 | ) | (256 | ) | (161 | ) | 12.1 | % | 78.3 | % | (543 | ) | (420 | ) | 29.3 | % | ||||||||||||||||
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| Net result before tax |
119 | 17 | 456 | 600.0 | % | -73.9 | % | 136 | 992 | -86.3 | % | |||||||||||||||||||||
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| Income tax |
(61 | ) | (27 | ) | 79 | 125.9 | % | N/A | (88 | ) | 200 | N/A | ||||||||||||||||||||
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| Net result |
58 | (10 | ) | 535 | N/A | -89.2 | % | 48 | 1,192 | -96.0 | % | |||||||||||||||||||||
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| Net Income before impairment of assets |
52 | (10 | ) | 538 | N/A | -90.3 | % | 42 | 1,195 | -96.5 | % | |||||||||||||||||||||
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Financial net results recorded a loss of US$287 million (vs. a loss of US$256 million in 1Q25), mostly explained by updated liabilities and lower domestic interest income rates. Income tax recorded a charge of US$61 million (vs. a charge of US$27 million in 1Q25) due to higher future tax payables. Consequently, net result totaled a gain of US$58 million (vs. a loss of US$10 million in 1Q25).
2. ADJ. EBITDA & CAPEX
2.1 ADJ. EBITDA RECONCILIATION
| Reconciliation of Adjusted EBITDA Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Net result |
58 | (10 | ) | 535 | N/A | -89.2 | % | 48 | 1,192 | -96.0 | % | |||||||||||||||||||||
| Financial results, net |
287 | 256 | 161 | 12.1 | % | 78.3 | % | 543 | 420 | 29.3 | % | |||||||||||||||||||||
| Result from equity interests in associates and joint ventures |
6 | (81 | ) | (27 | ) | N/A | N/A | (75 | ) | (156 | ) | -51.9 | % | |||||||||||||||||||
| Income tax |
61 | 27 | (79 | ) | 125.9 | % | N/A | 88 | (200 | ) | N/A | |||||||||||||||||||||
| Unproductive exploratory drillings |
1 | — | 49 | N/A | -98.0 | % | 1 | 55 | -98.2 | % | ||||||||||||||||||||||
| Depreciation & amortization |
788 | 806 | 638 | -2.2 | % | 23.5 | % | 1,594 | 1,290 | 23.6 | % | |||||||||||||||||||||
| Reversal / (Impairment) of PP&E |
(9 | ) | — | 5 | N/A | N/A | (9 | ) | 5 | N/A | ||||||||||||||||||||||
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| EBITDA |
1,192 | 998 | 1,282 | 19.4 | % | -7.0 | % | 2,190 | 2,606 | -16.0 | % | |||||||||||||||||||||
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| Leasing |
(82 | ) | (85 | ) | (78 | ) | -4.0 | % | 4.3 | % | (167 | ) | (157 | ) | 5.8 | % | ||||||||||||||||
| Provision for operating optimizations |
30 | — | — | N/A | N/A | 30 | — | N/A | ||||||||||||||||||||||||
| Result from sale of assets |
(168 | ) | (14 | ) | — | 1120.3 | % | N/A | (182 | ) | — | N/A | ||||||||||||||||||||
| Result from changes in fair value of assets held for sale |
44 | 200 | — | -78.0 | % | N/A | 244 | — | N/A | |||||||||||||||||||||||
| Provision for severance indemnities |
0 | 26 | — | -100.0 | % | N/A | 26 | — | N/A | |||||||||||||||||||||||
| Provision for obsolescence of materials and equipment |
123 | 136 | — | -9.5 | % | N/A | 259 | — | N/A | |||||||||||||||||||||||
| Result from revaluation of companies |
(45 | ) | — | — | N/A | N/A | (45 | ) | — | N/A | ||||||||||||||||||||||
| Miscellaneous – Mature Fields |
29 | (16 | ) | — | N/A | N/A | 13 | — | N/A | |||||||||||||||||||||||
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| Adjusted EBITDA |
1,124 | 1,245 | 1,204 | -9.7 | % | -6.7 | % | 2,368 | 2,449 | -3.3 | % | |||||||||||||||||||||
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2.2 ADJ. EBITDA & CAPEX BY SEGMENT
| By Segment |
2Q25 | 1Q25 | Q/Q Δ | 2Q24 | Y/Y Δ | 1H25 | 1H24 | Δ | ||||||||||||||||||||||||
| Adj. EBITDA |
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| Upstream |
770 | 766 | 1 | % | 815 | -6 | % | 1,537 | 1,646 | -7 | % | |||||||||||||||||||||
| Midstream & Downstream |
439 | 504 | -13 | % | 390 | 12 | % | 943 | 966 | -2 | % | |||||||||||||||||||||
| LNG & IG |
(0 | ) | (5 | ) | -99 | % | (22 | ) | -100 | % | (5 | ) | (54 | ) | -91 | % | ||||||||||||||||
| New Energies |
26 | 38 | -32 | % | 45 | -43 | % | 64 | 31 | 106 | % | |||||||||||||||||||||
| Corp |
(42 | ) | (36 | ) | 18 | % | (47 | ) | -11 | % | (78 | ) | (54 | ) | 43 | % | ||||||||||||||||
| Eliminations & Others |
(68 | ) | (24 | ) | 187 | % | 22 | N/A | (92 | ) | (86 | ) | 7 | % | ||||||||||||||||||
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| Total Adj. EBITDA |
1,124 | 1,245 | -10 | % | 1,204 | -7 | % | 2,369 | 2,449 | -3 | % | |||||||||||||||||||||
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| CAPEX |
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| Upstream |
864 | 979 | -12 | % | 863 | 0 | % | 1,843 | 1,798 | 3 | % | |||||||||||||||||||||
| Midstream & Downstream |
246 | 204 | 20 | % | 305 | -19 | % | 450 | 509 | -12 | % | |||||||||||||||||||||
| LNG & IG |
14 | 3 | 367 | % | 5 | 205 | % | 17 | 5 | 240 | % | |||||||||||||||||||||
| New Energies |
8 | 10 | -23 | % | 7 | 9 | % | 19 | 12 | 50 | % | |||||||||||||||||||||
| Corp |
28 | 18 | 54 | % | 20 | 39 | % | 46 | 45 | 2 | % | |||||||||||||||||||||
| Eliminations |
— | — | N/A | — | N/A | — | — | N/A | ||||||||||||||||||||||||
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| Total CAPEX |
1,160 | 1,214 | -5 | % | 1,200 | -3 | % | 2,374 | 2,369 | 0 | % | |||||||||||||||||||||
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Note: Midstream & Dw Adjusted EBITDA excludes inventories price effect of oil products, which are included in Eliminations & Other.
Page 4/14
3. ANALYSIS OF RESULTS BY SEGMENT
3.1 UPSTREAM
| Upstream Financials Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Crude oil |
1,325 | 1,646 | 1,568 | -19.5 | % | -15.5 | % | 2,971 | 3,127 | -5.0 | % | |||||||||||||||||||||
| Natural gas |
541 | 394 | 510 | 37.5 | % | 6.0 | % | 935 | 864 | 8.1 | % | |||||||||||||||||||||
| Other |
29 | 27 | 35 | 7.1 | % | -15.6 | % | 57 | 68 | -17.5 | % | |||||||||||||||||||||
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| Revenues |
1,895 | 2,067 | 2,113 | -8.3 | % | -10.3 | % | 3,962 | 4,060 | -2.4 | % | |||||||||||||||||||||
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| Depreciation & amortization |
(588 | ) | (602 | ) | (449 | ) | -2.4 | % | 30.9 | % | (1,190 | ) | (922 | ) | 29.0 | % | ||||||||||||||||
| Lifting cost |
(611 | ) | (758 | ) | (793 | ) | -19.3 | % | -22.9 | % | (1,369 | ) | (1,410 | ) | -2.9 | % | ||||||||||||||||
| Royalties |
(241 | ) | (262 | ) | (279 | ) | -8.1 | % | -13.5 | % | (503 | ) | (534 | ) | -5.7 | % | ||||||||||||||||
| Other costs |
(279 | ) | (564 | ) | (230 | ) | -50.5 | % | 21.2 | % | (843 | ) | (431 | ) | 95.3 | % | ||||||||||||||||
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| Operating income before impairment of assets |
176 | (119 | ) | 362 | N/A | -51.4 | % | 57 | 762 | -92.5 | % | |||||||||||||||||||||
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| Reversal / (Impairment) of PP&E |
— | — | — | N/A | N/A | — | — | N/A | ||||||||||||||||||||||||
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| Operating income / (loss) |
176 | (119 | ) | 362 | N/A | -51.4 | % | 57 | 762 | -92.5 | % | |||||||||||||||||||||
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| Depreciation & amortization |
588 | 602 | 449 | -2.4 | % | 30.9 | % | 1,190 | 922 | 29.0 | % | |||||||||||||||||||||
| Unproductive exploratory drillings |
1 | — | 49 | N/A | -98.0 | % | 1 | 55 | -98.2 | % | ||||||||||||||||||||||
| Reversal / (Impairment) of PP&E |
— | — | — | N/A | N/A | — | — | N/A | ||||||||||||||||||||||||
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| EBITDA |
765 | 483 | 860 | 58.2 | % | -11.1 | % | 1,248 | 1,739 | -28.2 | % | |||||||||||||||||||||
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| Leasing |
(51 | ) | (49 | ) | (44 | ) | 5.5 | % | 16.1 | % | (100 | ) | (93 | ) | 7.4 | % | ||||||||||||||||
| Provision for operating optimizations |
30 | — | — | N/A | N/A | 30 | — | N/A | ||||||||||||||||||||||||
| Result from sale of assets |
(168 | ) | (14 | ) | — | 1120.3 | % | N/A | (182 | ) | — | N/A | ||||||||||||||||||||
| Result from changes in fair value of assets held for sale |
44 | 200 | — | -78.0 | % | N/A | 244 | — | N/A | |||||||||||||||||||||||
| Provision for severance indemnities |
— | 26 | — | N/A | N/A | 26 | — | N/A | ||||||||||||||||||||||||
| Provision for obsolescence of materials and equipment |
123 | 136 | — | -9.5 | % | N/A | 259 | — | N/A | |||||||||||||||||||||||
| Miscellaneous – Mature Fields |
29 | (16 | ) | — | N/A | N/A | 13 | — | N/A | |||||||||||||||||||||||
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| Adjusted EBITDA |
771 | 766 | 816 | 0.6 | % | -5.5 | % | 1,538 | 1,646 | -6.6 | % | |||||||||||||||||||||
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| CAPEX |
864 | 979 | 863 | -11.7 | % | 0.1 | % | 1,843 | 1,798 | 2.5 | % | |||||||||||||||||||||
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| Unit Cash Costs Unaudited Figures, in US$/boe |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Lifting Cost |
12.3 | 15.3 | 16.2 | -19.3 | % | -23.9 | % | 13.8 | 14.6 | -5.3 | % | |||||||||||||||||||||
| Royalties and other taxes |
6.2 | 6.6 | 7.2 | -6.8 | % | -14.0 | % | 6.4 | 6.9 | -7.6 | % | |||||||||||||||||||||
| Other Costs |
3.4 | 3.4 | 3.5 | -0.8 | % | -3.1 | % | 3.4 | 3.0 | 13.2 | % | |||||||||||||||||||||
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| Total Cash Costs (US$/boe) |
21.8 | 25.3 | 26.8 | -13.5 | % | -18.5 | % | 23.6 | 24.4 | -3.5 | % | |||||||||||||||||||||
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Revenues totaled US$1,895 million (-8% q/q), mainly driven by lower oil prices associated with Brent contraction and decreased conventional oil production (due to further divestment of mature fields), partially offset by peak seasonal sales of natural gas (also boosted by shale gas expansion).
Lifting costs decreased to US$12.3/BOE (-19% q/q), mainly as a result of already divested mature fields. Conventional was US$26.8/BOE (-12% q/q) and unconventional was US$4.1/BOE (-22% q/q, boosted by productivity in the blocks of La Calera, wet gas window, and Lindero Atravesado, South Hub). Excluding mature fields, total lifting cost would have been around US$7.5/BOE.
Zooming into the lifting costs in our shale core hub blocks (at 100% stake), it recorded US$4.9/BOE, a competitive level despite the sequential increase (+7% q/q), mainly due to higher pulling and maintenance costs.
Royalties and other taxes averaged US$6.2/BOE (-7% q/q), mostly due to lower crude oil prices, partially offset by higher gas prices.
Other costs amounted to US$279 million (-51% q/q), mainly explained by the one-off costs related to mature fields mentioned above, partially offset by the positive results from sale of 49% of Aguada del Chañar.
Adj. EBITDA totaled US$771 million (+1% q/q). Despite Brent volatility that reduced oil prices, it was mainly boosted by higher seasonal gas sales and enhanced lifting cost driven by lower exposure to mature fields.
CAPEX amounted to US$864 million (-12% q/q). Despite having lower working interest in Aguada del Chañar block in 2Q25, over 95% was allocated to unconventional assets (vs. 93% in 1Q25), mostly destined to drilling and workover activities.
Page 5/14
Unconventional horizontal oil wells recorded again strong metrics, particularly tied-in activities: (# oil wells)
Note: (1) 1H25 accumulated 95 operated & 10 non-operated.
In terms of efficiencies within our unconventional operations, we achieved new record highs in line with the targets set for 2025. In this sense, we averaged 331 meters/day of drilling speed in our core-hub blocks (+9% q/q), and 259 stages/set-month of fracking speed (+10% q/q).
| Upstream Operating data Unaudited Figures |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Net Production Breakdown |
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| Crude Production (Kbbld) |
247.9 | 269.9 | 248.8 | -8.2 | % | -0.4 | % | 258.8 | 252.1 | 2.7 | % | |||||||||||||||||||||
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| Conventional |
101.7 | 121.2 | 133.1 | -16.1 | % | -23.6 | % | 111.4 | 137.0 | -18.7 | % | |||||||||||||||||||||
| Shale |
145.1 | 147.3 | 113.3 | -1.5 | % | 28.1 | % | 146.2 | 112.8 | 29.6 | % | |||||||||||||||||||||
| Tight |
1.0 | 1.4 | 2.4 | -26.4 | % | -58.5 | % | 1.2 | 2.3 | -49.8 | % | |||||||||||||||||||||
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| NGL Production (Kbbld) |
48.0 | 47.3 | 46.1 | 1.5 | % | 4.2 | % | 47.7 | 43.9 | 8.5 | % | |||||||||||||||||||||
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| Conventional |
12.5 | 12.8 | 10.4 | -2.4 | % | 20.1 | % | 12.7 | 10.5 | 20.3 | % | |||||||||||||||||||||
| Shale |
35.1 | 33.8 | 34.5 | 3.9 | % | 1.8 | % | 34.5 | 32.2 | 6.9 | % | |||||||||||||||||||||
| Tight |
0.4 | 0.7 | 1.2 | -39.9 | % | -64.2 | % | 0.6 | 1.2 | -53.3 | % | |||||||||||||||||||||
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| Gas Production (Mm3d) |
39.7 | 37.3 | 38.8 | 6.4 | % | 2.3 | % | 38.5 | 37.6 | 2.5 | % | |||||||||||||||||||||
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| Conventional |
11.1 | 11.4 | 12.8 | -3.2 | % | -13.7 | % | 11.3 | 13.0 | -13.2 | % | |||||||||||||||||||||
| Shale |
25.0 | 22.2 | 21.0 | 12.7 | % | 19.0 | % | 23.6 | 19.5 | 21.0 | % | |||||||||||||||||||||
| Tight |
3.6 | 3.7 | 4.9 | -1.9 | % | -27.0 | % | 3.6 | 5.1 | -28.5 | % | |||||||||||||||||||||
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| Total Production (Kboed) |
545.7 | 552.1 | 539.0 | -1.2 | % | 1.2 | % | 548.9 | 532.5 | 3.1 | % | |||||||||||||||||||||
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| Conventional |
183.9 | 206.0 | 224.2 | -10.7 | % | -18.0 | % | 194.9 | 229.0 | -14.9 | % | |||||||||||||||||||||
| Shale |
337.7 | 320.9 | 280.1 | 5.2 | % | 20.6 | % | 329.4 | 267.9 | 22.9 | % | |||||||||||||||||||||
| Tight |
24.1 | 25.2 | 34.6 | -4.3 | % | -30.4 | % | 24.6 | 35.6 | -30.8 | % | |||||||||||||||||||||
| Average realization prices |
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| Crude Oil (USD/bbl) |
59.5 | 67.9 | 70.8 | -12.4 | % | -16.0 | % | 63.9 | 69.5 | -8.2 | % | |||||||||||||||||||||
| Natural Gas (USD/MMBTU) |
4.1 | 3.0 | 4.0 | 37.8 | % | 1.9 | % | 3.5 | 3.5 | 0.5 | % | |||||||||||||||||||||
Crude oil production averaged 248 kbbl/d (-8% q/q), mainly due to the lower conventional output (-16% q/q), as we progressed with the closing of mature field transactions, and slightly lower shale oil production (-1.5% q/q) due to reduced working interest in Aguada del Chañar block.
Natural gas production grew by +6% q/q, mainly explained by the winter peak season (boosted by increased shale gas output of Rincón del Mangrullo and Aguada de la Arena blocks). NGLs production grew +1.5% q/q, backed on increased associated gas output from certain shale oil fields.
Page 6/14
3.2 MIDSTREAM & DOWNSTREAM
| Midstream & Downstream Financials Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Diesel (third parties) |
1,526 | 1,521 | 1,672 | 0.4 | % | -8.7 | % | 3,047 | 3,227 | -5.6 | % | |||||||||||||||||||||
| Gasoline (third parties) |
923 | 1,037 | 946 | -10.9 | % | -2.4 | % | 1,960 | 1,968 | -0.4 | % | |||||||||||||||||||||
| Other domestic market |
611 | 641 | 686 | -4.6 | % | -10.9 | % | 1,252 | 1,267 | -1.2 | % | |||||||||||||||||||||
| Export market |
680 | 720 | 690 | -5.6 | % | -1.5 | % | 1,399 | 1,322 | 5.8 | % | |||||||||||||||||||||
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| Revenues |
3,741 | 3,918 | 3,994 | -4.5 | % | -6.3 | % | 7,659 | 7,784 | -1.6 | % | |||||||||||||||||||||
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| Depreciation & amortization |
(162 | ) | (165 | ) | (156 | ) | -1.6 | % | 3.7 | % | (327 | ) | (305 | ) | 7.1 | % | ||||||||||||||||
| OPEX Downstream |
(527 | ) | (535 | ) | (559 | ) | -1.4 | % | -5.6 | % | (1,062 | ) | (997 | ) | 6.5 | % | ||||||||||||||||
| Fuels imports (including jet fuel—third parties) |
(53 | ) | (59 | ) | 0 | -10.1 | % | N/A | (112 | ) | (99 | ) | 13.2 | % | ||||||||||||||||||
| Crude oil purchases (intersegment + third parties) |
(1,765 | ) | (2,131 | ) | (2,037 | ) | -17.2 | % | -13.4 | % | (3,896 | ) | (3,971 | ) | -1.9 | % | ||||||||||||||||
| Biofuel purchases (third parties) |
(244 | ) | (226 | ) | (224 | ) | 8.2 | % | 9.2 | % | (470 | ) | (465 | ) | 1.0 | % | ||||||||||||||||
| Agro products purchases (third parties) |
(224 | ) | (119 | ) | (190 | ) | 88.4 | % | 17.6 | % | (342 | ) | (261 | ) | 31.3 | % | ||||||||||||||||
| Stock variations |
(114 | ) | 104 | (8 | ) | N/A | 1244.1 | % | (10 | ) | 108 | N/A | ||||||||||||||||||||
| Other |
(366 | ) | (406 | ) | (519 | ) | -9.8 | % | -29.4 | % | (772 | ) | (933 | ) | -17.3 | % | ||||||||||||||||
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| Operating income / (loss) before impairment of assets |
286 | 382 | 301 | -25.2 | % | -5.1 | % | 668 | 861 | -22.4 | % | |||||||||||||||||||||
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| Reversal / (Impairment) of PP&E |
— | — | — | N/A | N/A | — | — | N/A | ||||||||||||||||||||||||
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| Operating income / (loss) |
286 | 382 | 301 | -25.2 | % | -5.1 | % | 668 | 861 | -22.4 | % | |||||||||||||||||||||
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| Depreciation & amortization |
162 | 165 | 156 | -1.6 | % | 3.7 | % | 327 | 305 | 7.1 | % | |||||||||||||||||||||
| Reversal / (Impairment) of PP&E |
— | — | — | N/A | N/A | — | — | N/A | ||||||||||||||||||||||||
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| EBITDA |
448 | 547 | 457 | -18.1 | % | -2.1 | % | 995 | 1,166 | -14.7 | % | |||||||||||||||||||||
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| Leasing |
(29 | ) | (36 | ) | (34 | ) | -19.3 | % | -15.6 | % | (64 | ) | (64 | ) | 0.4 | % | ||||||||||||||||
| Result from revaluation of compañíes |
(44 | ) | — | — | N/A | N/A | (44 | ) | — | N/A | ||||||||||||||||||||||
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| Adjusted EBITDA |
376 | 511 | 423 | -26.5 | % | -11.2 | % | 887 | 1,102 | -19.5 | % | |||||||||||||||||||||
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| Inventories price effect of oil products |
(63 | ) | 7 | 34 | N/A | N/A | (56 | ) | 136 | N/A | ||||||||||||||||||||||
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| Adjusted EBITDA excl. inventories price effect of oil products |
439 | 504 | 390 | -13.0 | % | 12.6 | % | 943 | 966 | -2.4 | % | |||||||||||||||||||||
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| CAPEX |
246 | 204 | 305 | 20.4 | % | -19.3 | % | 450 | 509 | -11.6 | % | |||||||||||||||||||||
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Stock variations include price effects by US$6 million in 2Q24, (US$1) million for 1Q25, (US$83) million for 2Q25, (US$91) million for 1H25 and (US$127) million for 1H24.
Revenues totaled US$3.7 billion (-5% q/q), mainly explained by Brent drop impact on refined products, particularly local fuel prices, partially offset by seasonal sales of agricultural products (exports of grain and flours also boosted by lower export duties) and local diesel demand, and to a minor extent, increased oil exports.
OPEX Downstream amounted to US$527 million (-1% q/q), mainly due to lower fuel transportation costs, partially offset by higher costs related to refinery maintenances in 2Q25.
Fuel imports reached US$53 million (-10% q/q), mainly explained by lower unit cost related to a downward trend in international reference prices. Therefore, total fuel imports remained at low levels, representing only 3% of total fuel sales, compared to 2% in 1Q25 and 0% in 2Q24.
Crude oil purchases (intersegment + third parties) were US$1,765 million (-17% q/q), mostly due to lower oil prices, in line with Brent volatility, and lower processing levels due to the stoppage at La Plata Refinery in May. Biofuel purchases increased 8% q/q, mainly due to a 22% growth in biodiesel (+19% in volume and +2% in price), mainly to supply diesel seasonal demand, slightly offset by 5% decrease in bioethanol (-4% in volume and -1% in price), in line with gasoline demand. Agro products purchases grew by 88% q/q, primarily in line with higher seasonal demand of grains and fertilizers.
Stock variations totaled a negative US$114 million (vs. a positive US$104 million in 1Q25), primarily driven by consumption of inventory in 2Q25 to meet the demand during the programmed maintenance in May. This effect was also affected by lower oil prices in 2Q25.
Other costs decreased by 10% q/q, primarily driven by the revaluation of Loma Campana – Lago Pellegrini pipeline, slightly offset by higher Midstream Oil costs associated with the new additional capacity at Oldelval.
Adj. EBITDA, excluding inventories price effect of oil products, totaled US$439 million (-13% q/q), mainly due to lower international prices, which affected our local fuels and other refined products, as well as gasoline demand off-peak season. These effects were partially offset by lower cost of oil purchases, peak local diesel seasonal demand and increased oil exports.
Adj. EBITDA of the Refining & Marketing business, in unit terms, amounted to US$11.9/bbl (-17% q/q), primarily explained by local fuel price contraction (downward trend in international prices), coupled with higher costs related to programmed maintenances in refineries, slightly offset by lower cost of oil and OPEX efficiency.
Page 7/14
CAPEX was US$246 million (+20% q/q): 57% refining, 25% midstream (O&G), 14% logistics and 4% others.
In our refineries, CAPEX was allocated for the following main projects:
| • | New fuel specifications project, to comply with the Resolution No. 492/2023 of the Secretary of Energy. In that sense, the construction of a new diesel oil hydrotreatment unit at Luján de Cuyo refinery continued making progress, expecting to be operational in 1H26. |
| • | Revamping of topping units at Luján de Cuyo refinery, we continue making progress in the reconditioning of the refinery to process Vaca Muerta’s shale oil, expected to be in place in 3Q25. |
In our midstream oil business unit, we continued moving forward with our main projects:
| • | VMOS oil export pipeline (~550 kbbl/d by 1H27, ~US$3 billion CAPEX, YPF stake: ~25%): the SPV signed a syndicated loan for US$2 billion at SOFR+5.5% in Jul-25 to finance ~70% of the CAPEX, reopening Project Finance in Argentina. Construction progress: 23% (Jul-25), it completed welding works of ~120 km (Allen – 1° pumping station). |
| • | VMOC (Loma Campana – Allen, ~130 km pipeline): started its operations during 2Q25, serving as a connection point to Oldelval system and to fulfill the VMOS (export dedicated pipeline) once it is operational. |
| • | OldelVal Duplicar Plus: in Apr-25 expanded its capacity by 210 kbbl/d, reaching a total evacuation capacity of 540 kbbl/d. |
| • | OldelVal Duplicar Norte (Puesto Hernández – Allen): ~185 kbbl/d capacity expansion in two stages (1° in Jan-27 & 2° in Jun-27), with an estimated CAPEX of ~US$380 million. YPF expects not to join this project. |
| • | Connection of new areas and expansion of storage capacity: during May-25, completed the revamping works on Puesto Hernández – Luján de Cuyo oil pipeline, increasing the transportation capacity from the Neuquina basin to Luján de Cuyo refinery. |
In our midstream gas business unit, we also continued making progress on our main projects:
| • | Fully Revamping of the natural gas treatment plant at Loma La Lata, increasing the current capacity of the plant and improving the treatment of associated gas. It is expected to be operational in 1Q26. |
| • | South Hub gathering project to expand gas processing capacity at Sierra Barrosa treatment plants. We already completed the first stage in 2024, and launched the second phase in 1Q25, expecting to complete the project in 2027. |
| • | North Hub gathering project, construction of a gas pipeline connecting Narambuena and Bajo del Toro blocks with El Portón Industrial Complex, expecting to be operational in 2027. |
| Midstream & Downstream Operating data Unaudited Figures |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Crude processed (Kbbld) |
301.4 | 318.0 | 299.2 | -5.2 | % | 0.7 | % | 309.6 | 300.1 | 3.2 | % | |||||||||||||||||||||
| Refinery utilization (%) |
89.2 | % | 94.1 | % | 88.5 | % | -491bps | 65bps | 91.6 | % | 88.8 | % | 281bps | |||||||||||||||||||
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| Nominal capacity at 337.94 Kbbl/d since 1Q24. |
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| Sales volume to third parties (YPF stand alone) |
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| Sales of refined products (Km3) |
4,876 | 4,791 | 4,633 | 1.8 | % | 5.2 | % | 9,667 | 9,325 | 3.7 | % | |||||||||||||||||||||
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| Total domestic market |
4,477 | 4,212 | 4,166 | 6.3 | % | 7.5 | % | 8,689 | 8,306 | 4.6 | % | |||||||||||||||||||||
| of which Gasoline |
1,413 | 1,480 | 1,350 | -4.5 | % | 4.7 | % | 2,893 | 2,861 | 1.1 | % | |||||||||||||||||||||
| of which Diesel |
2,119 | 1,925 | 2,082 | 10.1 | % | 1.8 | % | 4,044 | 4,059 | -0.4 | % | |||||||||||||||||||||
| Total export market |
398 | 579 | 468 | -31.2 | % | -14.8 | % | 978 | 1,019 | -4.1 | % | |||||||||||||||||||||
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| Sales of petrochemical products (Ktn) |
145 | 109 | 150 | 32.7 | % | -3.3 | % | 254 | 302 | -15.9 | % | |||||||||||||||||||||
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| Domestic market |
52 | 58 | 75 | -10.3 | % | -29.8 | % | 111 | 140 | -20.7 | % | |||||||||||||||||||||
| Export market |
92 | 51 | 75 | 82.4 | % | 22.9 | % | 143 | 162 | -11.8 | % | |||||||||||||||||||||
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| Sales of fertilizers, grain and flours (Ktn) |
559 | 396 | 476 | 41.1 | % | 17.3 | % | 954 | 679 | 40.6 | % | |||||||||||||||||||||
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| Domestic market |
124 | 82 | 197 | 50.4 | % | -37.0 | % | 206 | 337 | -38.7 | % | |||||||||||||||||||||
| Export market |
434 | 313 | 279 | 38.7 | % | 55.5 | % | 748 | 341 | 119.0 | % | |||||||||||||||||||||
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| Net average prices |
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| Gasoline (USD/m3) (domestic market) |
596 | 640 | 640 | -6.9 | % | -6.9 | % | 618 | 630 | -1.9 | % | |||||||||||||||||||||
| Diesel (USD/m3) (domestic market) |
672 | 743 | 760 | -9.5 | % | -11.5 | % | 743 | 753 | -1.4 | % | |||||||||||||||||||||
| Petrochemical & others refined products (USD/bbl) |
72 | 74 | 73 | -2.0 | % | -1.4 | % | 73 | 71 | 3.5 | % | |||||||||||||||||||||
Net Average domestic prices for gasoline and diesel are net of taxes, commissions, commercial bonuses and freights.
Page 8/14
Crude oil processed averaged 301 kbbl/d (-5% q/q), reaching almost 90% of refinery utilization, mainly due to limited availability at La Plata Refinery (affected by a programmed maintenance in May).
Domestic fuels sales volumes reached 3,532 km3 (+4% q/q), on the back of higher diesel seasonal demand, slightly offset by off-peak gasoline demand.
Petrochemicals sales volumes grew by 33% q/q, mainly due to higher foreign methanol demand.
Fertilizers, grain and flours sales volumes increased by 41% q/q, mostly explained by higher seasonal demand, especially of grains, boosted also by lower export duties.
Net average fuels prices in the domestic market measured in dollar terms decreased by 8% q/q, mainly due to lower international references, partially offset by price adjustments. As a result, the gap with import parities moved to -1% (vs. +1% in 1Q25 and -5% in 2Q24).
Prices for petrochemical & other refined products contracted by 2% q/q, aligned with a downward trend in international prices of petrochemical and certain refined products, primarily jet fuel, coal and LPG.
3.3 LNG & INTEGRATED GAS
| LNG & Integrated Gas Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Natural gas (intersegment + third parties) |
539 | 383 | 524 | 40.9 | % | 2.9 | % | 922 | 876 | 5.3 | % | |||||||||||||||||||||
| Other |
26 | 17 | 23 | 50.2 | % | 11.9 | % | 43 | 37 | 14.1 | % | |||||||||||||||||||||
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| Revenues |
565 | 400 | 547 | 41.3 | % | 3.3 | % | 965 | 913 | 5.7 | % | |||||||||||||||||||||
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| Depreciation & amortization |
(0 | ) | (1 | ) | (0 | ) | -33.6 | % | 50.6 | % | (1 | ) | (1 | ) | 50.4 | % | ||||||||||||||||
| Natural gas purchases (intersegment + third parties) |
(532 | ) | (405 | ) | (518 | ) | 31.3 | % | 2.7 | % | (937 | ) | (870 | ) | 7.8 | % | ||||||||||||||||
| Operating cost & Other |
(33 | ) | 1 | (51 | ) | N/A | -35.7 | % | (32 | ) | (98 | ) | -67.4 | % | ||||||||||||||||||
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| Operating income before impairment of assets |
— | (5 | ) | (22 | ) | N/A | N/A | (5 | ) | (55 | ) | -90.9 | % | |||||||||||||||||||
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| Reversal / (Impairment) of PP&E |
— | — | — | N/A | N/A | — | — | N/A | ||||||||||||||||||||||||
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| Operating income |
— | (5 | ) | (22 | ) | N/A | N/A | (5 | ) | (55 | ) | -90.9 | % | |||||||||||||||||||
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| Depreciation & amortization |
0 | 1 | 0 | -33.6 | % | 50.6 | % | 1 | 1 | 50.4 | % | |||||||||||||||||||||
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| EBITDA |
0 | (4 | ) | (22 | ) | N/A | N/A | (4 | ) | (54 | ) | -92.6 | % | |||||||||||||||||||
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| Leasing |
(0 | ) | (0 | ) | — | -7.4 | % | N/A | (1 | ) | — | N/A | ||||||||||||||||||||
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| Adjusted EBITDA |
(0 | ) | (5 | ) | (22 | ) | -98.8 | % | -99.7 | % | (5 | ) | (54 | ) | -90.9 | % | ||||||||||||||||
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| CAPEX |
14 | 3 | 5 | 367.0 | % | 205.1 | % | 17 | 5 | 239.9 | % | |||||||||||||||||||||
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Adj. EBITDA balanced negative US$0.1 million (vs. a negative US$5 million in 1Q25), mainly due to the increased seasonal natural gas sales as producer, partially offset higher natural gas purchases and to a minor extent, a charge to doubtful debts.
CAPEX totaled US$14 million, growing significantly vs. 1Q25, mainly due to investments deployed in Argentina LNG project.
Regarding the aforementioned project, we made progress in:
| • | Argentina LNG: Phase 3 (~12 MTPA) signed in Jun-25 Heads Agreement with ENI, the strategic partner. Also, in Aug-25, SESA (YPF 25% equity stake), the SPV for Argentina LNG 1, obtained the FID approval for a 20-year bareboat charter agreement of the second vessel, MK II (3.5 MTPA, COD expected by 2028), and considering the first vessel (2.45 MTPA, COD expected by 2027), total capacity amounts to 5.95 MTPA. |
Page 9/14
3.4 NEW ENERGIES
| New Energies Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Natural gas retail (third parties) |
188 | 147 | 229 | 27.8 | % | -18.0 | % | 335 | 291 | 14.8 | % | |||||||||||||||||||||
| Other |
41 | 45 | 35 | -8.5 | % | 17.3 | % | 86 | 51 | 71.1 | % | |||||||||||||||||||||
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| Revenues |
229 | 192 | 264 | 19.3 | % | -13.3 | % | 421 | 342 | 23.1 | % | |||||||||||||||||||||
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| Depreciation & amortization |
(11 | ) | (14 | ) | (11 | ) | -23.5 | % | -5.3 | % | (25 | ) | (22 | ) | 12.9 | % | ||||||||||||||||
| Natural gas purchases (intersegment + third parties) |
(103 | ) | (57 | ) | (119 | ) | 78.5 | % | -13.9 | % | (160 | ) | (160 | ) | 0.0 | % | ||||||||||||||||
| Operating cost & Other |
(101 | ) | (96 | ) | (101 | ) | 4.4 | % | 0.1 | % | (197 | ) | (152 | ) | 29.7 | % | ||||||||||||||||
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| Operating income before impairment of assets |
15 | 24 | 33 | -37.5 | % | -54.5 | % | 39 | 8 | 387.5 | % | |||||||||||||||||||||
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| Reversal / (Impairment) of PP&E |
9 | — | (5 | ) | N/A | N/A | 9 | (5 | ) | N/A | ||||||||||||||||||||||
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| Operating income |
24 | 24 | 28 | 0.0 | % | -14.3 | % | 48 | 3 | 1500.0 | % | |||||||||||||||||||||
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| Depreciation & amortization |
11 | 14 | 11 | -23.5 | % | -5.3 | % | 25 | 22 | 12.9 | % | |||||||||||||||||||||
| Reversal / (Impairment) of PP&E |
(9 | ) | — | 5 | N/A | N/A | (9 | ) | 5 | N/A | ||||||||||||||||||||||
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| EBITDA |
26 | 38 | 44 | -32.3 | % | -41.9 | % | 64 | 30 | 112.3 | % | |||||||||||||||||||||
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| Leasing |
— | — | — | N/A | N/A | — | — | N/A | ||||||||||||||||||||||||
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| Adjusted EBITDA |
26 | 38 | 44 | -32.3 | % | -41.9 | % | 64 | 30 | 112.3 | % | |||||||||||||||||||||
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| CAPEX |
8 | 10 | 7 | -23.2 | % | 9.4 | % | 19 | 12 | 49.9 | % | |||||||||||||||||||||
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Adj. EBITDA totaled US$26 million (-32% q/q), primarily explained by increased gas purchases and a recognition of charge for doubtful debts, partially offset by higher seasonal retail gas demand supplied (higher tariff) by our subsidiary Metrogas.
4. LIQUIDITY AND SOURCES OF CAPITAL
4.1 CASH FLOW SUMMARY
| Summary Consolidated Cash Flow Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Cash BoP |
938 | 1,118 | 1,309 | -16.1 | % | -28.3 | % | 1,118 | 1,123 | -0.4 | % | |||||||||||||||||||||
| Net cash flow from operating activities |
1,146 | 850 | 1,422 | 34.8 | % | -19.4 | % | 1,996 | 2,511 | -20.5 | % | |||||||||||||||||||||
| Net cash flow from investing activities |
(1,258 | ) | (1,383 | ) | (1,464 | ) | -9.0 | % | -14.1 | % | (2,641 | ) | (2,672 | ) | -1.2 | % | ||||||||||||||||
| Net cash flow from financing activities |
20 | 354 | (206 | ) | -94.4 | % | N/A | 374 | 106 | 252.8 | % | |||||||||||||||||||||
| FX adjustments & other |
(72 | ) | (1 | ) | (20 | ) | 7100.0 | % | 260.0 | % | (73 | ) | (27 | ) | 170.4 | % | ||||||||||||||||
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| Cash EoP |
774 | 938 | 1,041 | -17.5 | % | -25.6 | % | 774 | 1,041 | -25.6 | % | |||||||||||||||||||||
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| Investment in financial assets |
237 | 292 | 353 | -18.8 | % | -32.9 | % | 237 | 353 | -32.9 | % | |||||||||||||||||||||
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| Cash + short-term investments EoP |
1,011 | 1,230 | 1,394 | -17.8 | % | -27.5 | % | 1,011 | 1,394 | -27.5 | % | |||||||||||||||||||||
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| FCF |
(365 | ) | (957 | ) | (257 | ) | -61.9 | % | 42.0 | % | (1,322 | ) | (651 | ) | 103.1 | % | ||||||||||||||||
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FCF = Cash flow from Operations less capex (Investing activities), M&A (Investing activities), and interest and leasing payments (Financing activities).
Free cash flow reached a negative US$365 million, mainly due to: (1) impact of mature fields for -US$189 million; (2) -US$101 million for income tax payment from subsidiaries (mainly from Metrogas & AESA); (3) regular debt services amounted to -US$100 million. Moreover, +US$142 million of dividend collection from our affiliates, net of contributions and prepayments to them, more than offset the negative working capital variations and others for -US$81 million. The latter was mostly due to peak seasonal sales of natural gas, agro products and payroll.
In terms of liquidity, our cash and short-term investments decreased to US$1,011 million by the end of June 2025, a contraction of 18% vs. 1Q25.
Page 10/14
4.2 NET DEBT
| Net debt breakdown Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | ||||||||||||
| Short-term debt |
2,252 | 2,023 | 1,651 | 11.3 | % | |||||||||||
| Long-term debt |
7,592 | 7,543 | 7,200 | 0.6 | % | |||||||||||
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| Total debt |
9,844 | 9,566 | 8,851 | 2.9 | % | |||||||||||
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| Avg. Interest rate for AR$-debt |
34.8 | % | 32.9 | % | 43.8 | % | ||||||||||
| Avg. Interest rate for US$-debt |
6.6 | % | 6.4 | % | 6.2 | % | ||||||||||
| % of debt in AR$ |
0.3 | % | 0.3 | % | 4.2 | % | ||||||||||
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| Cash + short term investments |
1,011 | 1,230 | 1,394 | -17.8 | % | |||||||||||
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| % of liquidity dollarized |
67.2 | % | 69.3 | % | 116.8 | % | ||||||||||
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| Net debt |
8,833 | 8,336 | 7,457 | 6.0 | % | |||||||||||
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Average interest rates for AR$ and US$ debt refer to YPF on a stand-alone basis.
As of June 30, 2025, YPF’s consolidated net debt totaled US$8,833 million (+US$497 million q/q), primarily driven by new local issuances, growing gross debt to US$9,844 million, while cash and short-term investments diminished, as mentioned in the previous section. As anticipated before, our net leverage ratio increased from 1.8x in 1Q25 to 1.9x in 2Q25, due to the closing of mature field transactions.
In terms of financing, during 2Q25 we tapped the local capital market, issuing two new bonds:
| 1) | US$-linked bond for US$204 million, with a 15-month tenor at 3.95% |
| 2) | Hard-US$ for US$140 million with a 2-year tenor at 7% |
We also secured around US$190 million in other local financing: ~US$150 million of trade financing and ~US$40 million in promissory notes.
After 2Q25, we issued in the local market: (i) a US$-MEP bond for US$250 million, with a 2-year tenor at 7.5%; and (ii) a US$-Cable tranche for US$167 million, with a 5-year tenor at 8.75%.
Additionally, during July, YPF’s credit rating was upgraded by Moody’s credit agency, after the upgrade in sovereign ratings: from Caa1 to B2, maintaining stable outlook.
Regarding our maturity profile, for the second half of 2025, the Company faces US$793 million of manageable maturities, mostly local: US$467 million of short-term trade facilities with local banks; US$120 million of export-backed bond amortizations; US$144 million of local bonds and promissory notes; and US$62 million of CAF and other financial facilities.
Page 11/14
The following chart shows our consolidated principal debt maturity profile as of June 30, 2025:
Page 12/14
5. TABLES
5.1 CONSOLIDATED BALANCE SHEET
| Consolidated Balance Sheet | ||||||||
| Unaudited Figures |
30-Jun-25 | 31-Dec-24 | ||||||
| Non-current Assets |
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| Intangible assets |
590 | 491 | ||||||
| Properties, plant and equipment |
19,348 | 18,736 | ||||||
| Assets for leasing |
672 | 743 | ||||||
| Investments in companies and joint ventures |
1,913 | 1,960 | ||||||
| Deferred tax assets, net |
231 | 330 | ||||||
| Other receivables |
760 | 337 | ||||||
| Trade receivables |
2 | 1 | ||||||
| Investment in financial assets |
0 | 0 | ||||||
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| Total Non-current Assets |
23,516 | 22,598 | ||||||
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| Current Assets |
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| Assets held for disposal |
529 | 1,537 | ||||||
| Inventories |
1,482 | 1,546 | ||||||
| Contract assets |
21 | 30 | ||||||
| Other receivables |
661 | 552 | ||||||
| Trade receivables |
1,795 | 1,620 | ||||||
| Investment in financial assets |
237 | 390 | ||||||
| Cash and cash equivalents |
774 | 1,118 | ||||||
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| Total Current Assets |
5,499 | 6,793 | ||||||
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| Total Assets |
29,015 | 29,391 | ||||||
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| Total Shareholders´ Equity |
11,924 | 11,870 | ||||||
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| Non-current Liabilities |
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| Provisions |
1,093 | 1,084 | ||||||
| Deferred tax liabilities, net |
104 | 90 | ||||||
| Contract liabilities |
167 | 114 | ||||||
| Income tax payable |
2 | 2 | ||||||
| Other taxes payable |
0 | 0 | ||||||
| Salaries and social security |
34 | 34 | ||||||
| Liabilities from leasing |
364 | 406 | ||||||
| Loans |
7,592 | 7,035 | ||||||
| Other liabilities |
384 | 74 | ||||||
| Accounts payable |
5 | 6 | ||||||
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| Total non-current Liabilities |
9,745 | 8,845 | ||||||
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| Current Liabilities |
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| Liabilities directly associated with assets held for sale |
945 | 2,136 | ||||||
| Provisions |
116 | 116 | ||||||
| Contract liabilities |
114 | 73 | ||||||
| Income tax payable |
28 | 126 | ||||||
| Other taxes payable |
282 | 247 | ||||||
| Salaries and social security |
289 | 412 | ||||||
| Liabilities from leasing |
345 | 370 | ||||||
| Loans |
2,252 | 1,907 | ||||||
| Other liabilities |
321 | 410 | ||||||
| Accounts payable |
2,654 | 2,879 | ||||||
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| Total Current Liabilities |
7,346 | 8,676 | ||||||
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| Total Liabilities |
17,091 | 17,521 | ||||||
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| Total Liabilities and Shareholders’ Equity |
29,015 | 29,391 | ||||||
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Note: Information reported in accordance with International Financial Reporting Standards (IFRS).
Page 13/14
5.2 CONSOLIDATED INCOME STATEMENT
| Income Statement Unaudited Figures, in US$ million |
2Q25 | 1Q25 | 2Q24 | Q/Q Δ | Y/Y Δ | 1H25 | 1H24 | Y/Y Δ | ||||||||||||||||||||||||
| Revenues |
4,641 | 4,608 | 4,935 | 0.7 | % | -6.0 | % | 9,249 | 9,245 | 0.0 | % | |||||||||||||||||||||
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| Costs |
(3,468 | ) | (3,329 | ) | (3,457 | ) | 4.2 | % | 0.3 | % | (6,797 | ) | (6,476 | ) | 5.0 | % | ||||||||||||||||
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| Gross profit |
1,173 | 1,279 | 1,478 | -8.3 | % | -20.6 | % | 2,452 | 2,769 | -11.4 | % | |||||||||||||||||||||
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| Selling expenses |
(535 | ) | (528 | ) | (577 | ) | 1.3 | % | -7.3 | % | (1,063 | ) | (1,044 | ) | 1.8 | % | ||||||||||||||||
| Administrative expenses |
(188 | ) | (206 | ) | (210 | ) | -8.7 | % | -10.5 | % | (394 | ) | (351 | ) | 12.3 | % | ||||||||||||||||
| Exploration expenses |
(21 | ) | (30 | ) | (88 | ) | -30.0 | % | -76.1 | % | (51 | ) | (111 | ) | -54.1 | % | ||||||||||||||||
| Reversal / (Impairment) of PP&E |
9 | — | (5 | ) | N/A | N/A | 9 | (5 | ) | N/A | ||||||||||||||||||||||
| Other operating results, net |
(26 | ) | (323 | ) | (8 | ) | -92.0 | % | 225.0 | % | (349 | ) | (2 | ) | 17350.0 | % | ||||||||||||||||
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| Operating income |
412 | 192 | 590 | 114.6 | % | -30.2 | % | 604 | 1,256 | -51.9 | % | |||||||||||||||||||||
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| Income of interests in companies and joint ventures |
(6 | ) | 81 | 27 | N/A | N/A | 75 | 156 | -51.9 | % | ||||||||||||||||||||||
| Financial Income |
28 | 16 | 32 | 75.0 | % | -12.5 | % | 44 | 68 | -35.3 | % | |||||||||||||||||||||
| Financial Cost |
(279 | ) | (285 | ) | (308 | ) | -2.1 | % | -9.4 | % | (564 | ) | (644 | ) | -12.4 | % | ||||||||||||||||
| Other financial results |
(36 | ) | 13 | 115 | N/A | N/A | (23 | ) | 156 | N/A | ||||||||||||||||||||||
| Financial results, net |
(287 | ) | (256 | ) | (161 | ) | 12.1 | % | 78.3 | % | (543 | ) | (420 | ) | 29.3 | % | ||||||||||||||||
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| Net profit before income tax |
119 | 17 | 456 | 600.0 | % | -73.9 | % | 136 | 992 | -86.3 | % | |||||||||||||||||||||
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| Income tax |
(74 | ) | (27 | ) | 79 | 174.1 | % | N/A | (101 | ) | 200 | N/A | ||||||||||||||||||||
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| Net profit for the period |
45 | (10 | ) | 535 | N/A | -91.6 | % | 35 | 1,192 | -97.1 | % | |||||||||||||||||||||
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| Net profit for shareholders of the parent company |
50 | (16 | ) | 519 | N/A | -90.4 | % | 34 | 1,168 | -97.1 | % | |||||||||||||||||||||
| Net profits for non-controlling interest |
8 | 6 | 16 | 33.3 | % | -50.0 | % | 14 | 24 | -41.7 | % | |||||||||||||||||||||
| Earnings per share attributable to shareholders of the parent company (basic and diluted) |
0.13 | (0.04 | ) | 1.32 | N/A | -90.2 | % | 0.09 | 2.98 | -97.0 | % | |||||||||||||||||||||
Note: Information reported in accordance with International Financial Reporting Standards (IFRS).
6. ABOUT YPF
YPF is the largest energy company in Argentina, fully integrated in the oil and gas value chain. Our main businesses are: (i) in the upstream, we produce ~40% and ~30% of the country’s oil and gas, respectively, and we are the largest shale producer in Vaca Muerta, in process of divestment of conventional mature fields; (ii) in the downstream, we operate 3 refineries (~50% of Argentina’s refining capacity) and lead the local diesel and gasoline sales (market share >55%); and (iii) in gas and power, Metrogas, our subsidiary, distributes ~25% of the country’s natural gas, while YPF Luz, our affiliate, is the third largest power generation company in Argentina. The Government is the controlling shareholder with a 51% stake, and YPF is listed in the NYSE and ByMA.
7. DISCLAIMER
Additional information about YPF S.A., a sociedad anónima organized under the laws of Argentina (the “Company” or “YPF”) can be found in the “Investors” section on the website at www.ypf.com.
This document does not constitute an offer to sell or the solicitation of any offer to buy any securities of the Company, in any jurisdiction. Securities may not be offered or sold in the United States absent registration with the U.S. Securities Exchange Commission (“SEC”), the Comisión Nacional de Valores (Argentine National Securities and Exchange Commission, or “CNV”) or an exemption from such registrations.
No reliance may be placed for any purpose whatsoever on the information contained in this document or on its completeness. Certain information contained in this document may have been obtained from published sources, which may not have been independently verified or audited. No representation or warranty, express or implied, is given or will be given by or on behalf of the Company, or any of its affiliates (within the meaning of Rule 405 under the Act, “Affiliates”), members, directors, officers or employees or any other person (the “Related Parties”) as to the accuracy, completeness or fairness of the information or opinions contained in this document or any other material discussed verbally, and any reliance you place on them will be at your sole risk. Any opinions presented herein are based on general information gathered at the time of writing and are subject to change without notice. In addition, no responsibility, obligation or liability (whether direct or indirect, in contract, tort or otherwise) is or will be accepted by the Company or any of its Related Parties in relation to such information or opinions or any other matter in connection with this document or its contents or otherwise arising in connection therewith.
This document may also include certain non-IFRS (International Financial Reporting Standards) financial measures which have not been subject to a financial audit for any period. The information and opinions contained in this document are provided as at the date of this document and are subject to verification, completion and change without notice.
This document includes “forward-looking statements” concerning the future. The words such as “believes,” “thinks,” “forecasts,” “expects,” “anticipates,” “intends,” “should,” “seeks,” “estimates,” “future” or similar expressions are included with the intention of identifying statements about the future. For the avoidance of doubt, any projection, guidance or similar estimation about the future or future results, performance or achievements is a forward-looking statement. Although the assumptions and estimates on which forward-looking statements are based are believed by our management to be reasonable and based on the best currently available information, such forward-looking statements are based on assumptions that are inherently subject to significant uncertainties and contingencies, many of which are beyond our control.
Forward-looking statements speak only as of the date on which they were made, and we undertake no obligation to release publicly any updates or revisions to any forward-looking statements contained herein because of new information, future events or other factors. In light of these limitations, undue reliance should not be placed on forward-looking statements contained in this document. Further information concerning risks and uncertainties associated with these forward-looking statements and YPF’s business can be found in YPF’s public disclosures filed on EDGAR (www.sec.gov) or at the web page of the Argentine National Securities and Exchange Commission (www.argentina.gob.ar/cnv).
You should not take any statement regarding past trends or activities as a representation that the trends or activities will continue in the future. Accordingly, you should not put undue reliance on these statements. This document is not intended to constitute and should not be construed as investment advice.
The information contained herein has been prepared to assist interested parties in making their own evaluations of YPF.
Page 14/14
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| YPF Sociedad Anónima | ||||||
| Date: August 7, 2025 | By: | /s/ Margarita Chun | ||||
| Name: | Margarita Chun | |||||
| Title: | Market Relations Officer | |||||
FAQ
How did YPF (YPF) perform financially in 2Q25?
What happened to YPF's free cash flow and debt levels?
How is YPF progressing on the VMOS oil export pipeline?
What portion of YPF's production is shale and how are costs trending?
Did credit ratings change for YPF in 2025?
