[6-K] YPF SOCIEDAD ANONIMA Current Report (Foreign Issuer)

Rhea-AI Filing Summary

YPF filed a Form 6‑K reporting Q3 2025 results. Revenue was US$4,643 million, flat sequentially as higher fuel demand and winter natural gas sales offset lower local fuel prices. Adjusted EBITDA reached US$1,357 million (+21% q/q), driven by stronger shale oil output, lower lifting costs from exiting mature fields, and record refinery throughput. The quarter closed with a net loss of US$198 million, reflecting a US$537 million income tax charge and US$245 million net financial loss.

Operationally, shale oil averaged 170 kbbl/d (+17% q/q; +35% y/y), representing 71% of total oil. Company lifting costs fell to US$8.8/boe (−28% q/q), while refineries processed 326 kbbl/d at a 97% utilization rate, a high since 2009. CAPEX was US$1,017 million, ~70% to unconventional assets. Free cash flow was −US$759 million, mainly due to the US$523 million shale asset acquisition and working capital. Net debt rose to US$9,595 million, with net leverage at 2.1x; pro forma 1.9x excluding the acquisition. After quarter‑end, YPF signed a US$700 million export‑backed facility and reopened its 2031 bond for US$500 million at 8.25% yield.

Insights

Energy sector analyst

Solid operations offset by tax/financing headwinds.

YPF delivered stronger operating performance: Adjusted EBITDA rose to US$1,357M on higher shale volumes, lower lifting costs, and record refinery utilization. Shale oil reached 71% of oil output, and lifting cost dropped to US$8.8/boe, underscoring the shift from mature fields.

Despite this, earnings were negative as a large income tax charge of US$537M and net financial loss of US$245M outweighed operating gains. Free cash flow of −US$759M reflected the US$523M shale acquisition and working capital movements, which also pushed net debt to US$9,595M and leverage to 2.1x.

Financing actions after the quarter—an export‑backed facility of US$700M and a 2031 bond tap of US$500M at 8.25% yield—address near‑term maturities and fund investments. Actual cash flow trends will hinge on fuel pricing, shale ramp continuity, and working capital normalization.

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 November 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 November 7, 2025.

MAIN HIGHLIGHTS OF 3Q25

KPI		3Q25				2Q25				Q/Q Δ				3Q24				Y/Y Δ				9M25				9M24				Δ
Financial
Revenues			4,643				4,641				0	%			5,297				-12	%			13,892				14,542				-4	%
Adjusted EBITDA			1,357				1,124				21	%			1,366				-1	%			3,726				3,815				-2	%
Net Result			(198	)			58				N/A				1,485				N/ A				(150	)			2,677				N/A
CAPEX			1,017				1,160				-12	%			1,353				-25	%			3,391				3,722				-9	%
FCF			(759	)			(365	)			108	%			(173	)			339	%			(2,081	)			(824	)			153	%
Net Debt			9,595				8,833				9	%			7,506				28	%			9,595				7,506				28	%
Net Leverage Ratio (x)			2.1				1.9				9	%			1.5				37	%			2.1				1.5				37	%
Upstream
Hydrocarbon Production (Kboe/d)			523.1				545.7				-4	%			558.7				-6	%			540.2				541.3				0	%
Crude Oil (Kbbl/d)			239.8				247.9				-3	%			255.8				-6	%			252.4				253.4				0	%
Natural Gas (Mm3/d)			38.4				39.7				-3	%			40.3				-5	%			38.5				38.5				0	%
NGL (Kbbl/d)			41.9				48.0				-13	%			49.5				-15	%			45.7				45.8				0	%
Crude Oil Price (US$/bbl)			60.0				59.5				1	%			68.3				-12	%			62.6				69.1				-9	%
Natural Gas Price (US$/MBTU)			4.3				4.1				6	%			4.5				-3	%			3.8				3.8				-1	%
Crude Oil Exports (Kbbl/d)			38.3				43.6				-12	%			41.3				-7	%			39.5				33.0				20	%
Shale Oil Production (Kbbl/d)			170.0				145.1				17	%			125.7				35	%			154.2				117.1				32	%
Total Lifting Cost (US$/boe)			8.8				12.3				-28	%			16.1				-45	%			12.2				15.1				-19	%
Core-Hub Lifting Cost (US$/boe)			4.6				4.9				-7	%			4.6				0	%			4.7				4.2				12	%
Midstream & Dw
Crude Processed (Kbbl/d)			326.2				301.4				8	%			298.3				9	%			315.2				299.5				5	%
Refineries’ Utilization Rate (%)			97	%			89	%			8	%			88	%			9	%			93	%			89	%			5	%
Local Fuels Volume Sold (Km3)			3,655				3,532				3	%			3,449				6	%			10,591				10,370				2	%
Local Fuels Net Price (US$/m3)			608				641				-5	%			716				-15	%			648				706				-8	%
Imported Fuels (Km3)			50				95				-48	%			123				-60	%			222				265				-16	%
R&M Adj. EBITDA (US$/bbl)			5.9				11.9				-50	%			13.1				-55	%			10.6				14.3				-26	%

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$1,357 million (+21% q/q), mainly driven by higher shale oil production, lower lifting costs related to the divestment of mature fields, higher seasonal sales of natural gas, in addition to record processing level at our refineries, partially offset by a slight contraction in local fuel prices based on a very volatile environment.

On a y/y basis, EBITDA remained essentially flat, despite a 13% interannual contraction in Brent’s price. The lower fuels prices were almost offset by higher shale oil production and lower lifting costs on the back of reduced exposure to mature fields. Moreover, processing levels stood 9% above last year.

CAPEX amounted to US$1,017 million, 12% below the previous quarter, mostly driven by lower cost in USD terms, from which 70% was allocated to the unconventional business, reaffirming our focus on Vaca Muerta.

Shale oil production continued delivering an impressive growth rate of 35% y/y averaging 170 kbbl/d (+17% q/q), representing 71% of our total oil production (2Q25: 59% and 3Q24: 49%), almost offsetting the decline in mature fields. Excluding the effect of the sale of Aguada del Chañar block, shale oil production would have increased by 43% y/y.

Lifting costs significantly dropped to 8.8 US$/boe (-28% q/q and -45% y/y), as the result of the successful exit strategy from conventional mature fields and increased shale production.

Processing levels at our refineries averaged 326 kbbl/d, record high since 2009, representing 97% of refineries’ utilization rate, mainly driven by higher processing levels at La Plata refinery that was awarded as the Refinery of the Year in Latin America by LARTC.

Progress on our main projects:

• VMOS: (construction progress ~35% as of Sep-25) during the quarter, works related to the oil pipeline routes and trench excavation were completed, on track with the plan. Moreover, in early Nov-25 welding works for the 440 km oil pipeline were completed.

• Argentina LNG: in Oct-25 YPF and ENI signed the technical FID for Phase 3 (~12 MTPA, expandable to ~18 MTPA). Moreover, in Nov-25, ADNOC, through XRG, its investment subsidiary, signed a preliminary framework agreement with YPF and ENI, aiming to join the Argentina LNG Project.

Free cash flow totaled a negative US$759 million in 3Q25, as expected, mostly explained by the extraordinary effects related to the recent acquisition of shale assets (US$523 million) and the impact of the mature fields exit strategy. As a result, net debt increased to 9.6 billion dollars, pushing our net leverage ratio up to 2.1x. Excluding the recent acquisition of shale assets, the net leverage ratio proforma would have amounted to 1.9x.

On the financial front, in October, YPF reopened the syndicated corporate cross-border loan market for US$700 million and retaped the 2031 international bond for US$500 million at 8.25% yield.

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Buenos Aires, Nov 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 3Q25

Consolidated Revenues Breakdown Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Diesel			1,467				1,526				1,646				-3.9	%			-10.9	%			4,514				4,873				-7.4	%
Gasoline			929				923				1,023				0.6	%			-9.1	%			2,890				2,991				-3.4	%
Natural gas as producers (third parties)			523				447				514				17.2	%			1.7	%			1,276				1,211				5.4	%
Other			1,067				1,025				1,366				4.0	%			-21.9	%			3,080				3,317				-7.2	%
Total Domestic Market			3,986				3,922				4,549				1.6	%			-12.4	%			11,760				12,393				-5.1	%
Jet fuel			87				73				125				19.7	%			-30.4	%			254				399				-36.4	%
Grain and flours			139				172				99				-19.0	%			41.0	%			444				255				73.8	%
Crude oil			238				254				285				-6.2	%			-16.5	%			732				700				4.5	%
Petchem & Other			193				221				240				-12.7	%			-19.4	%			703				795				-11.6	%
Total Export Market			657				719				748				-8.6	%			-12.2	%			2,132				2,149				-0.8	%
Total Revenues			4,643				4,641				5,297				0.0	%			-12.3	%			13,892				14,542				-4.5	%

Net Revenues amounted to US$4,643 million, flat against 2Q25, mainly due to increased fuel demand and peak natural gas sales during the winter, offset by lower gasoline and diesel prices. Moreover, Medanito oil exports volumes increased by 14% q/q, partially compensated by the extraordinary export of Escalante oil in 2Q25. Finally, grain and flour sales declined in 3Q25 due to lower seasonal demand.

Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Lifting cost			(426	)			(611	)			(827	)			-30.3	%			-48.5	%			(1,795	)			(2,238	)			-19.8	%
Other Upstream			(184	)			(158	)			(199	)			16.2	%			-7.7	%			(489	)			(473	)			3.5	%
OPEX Downstream			(520	)			(527	)			(572	)			-1.3	%			-9.1	%			(1,582	)			(1,570	)			0.8	%
Others Midstream & Downstream			(80	)			(71	)			(64	)			12.2	%			25.2	%			(206	)			(169	)			22.1	%
LNG & IG, New Energies, Corp. & Other			(146	)			(161	)			(300	)			-9.3	%			-51.2	%			(556	)			(735	)			-24.3	%
Total OPEX			(1,356	)			(1,529	)			(1,962	)			-11.3	%			-30.9	%			(4,629	)			(5,184	)			-10.7	%
Depreciation & Amortization			(836	)			(788	)			(674	)			6.1	%			24.0	%			(2,430	)			(1,964	)			23.7	%
Royalties			(238	)			(243	)			(294	)			-1.9	%			-19.1	%			(746	)			(834	)			-10.5	%
Other costs			(284	)			(312	)			(338	)			-9.1	%			-15.9	%			(915	)			(993	)			-7.9	%
Total Other Costs			(1,358	)			(1,343	)			(1,306	)			1.1	%			4.0	%			(4,091	)			(3,791	)			7.9	%
Fuels imports (including jet fuel)			(35	)			(53	)			(98	)			-33.2	%			-64.0	%			(147	)			(197	)			-25.3	%
Crude oil purchases to third parties			(688	)			(442	)			(471	)			55.9	%			46.2	%			(1,615	)			(1,315	)			22.9	%
Biofuel purchases			(208	)			(244	)			(233	)			-14.8	%			-10.9	%			(678	)			(698	)			-3.0	%
Agro products purchases			(226	)			(224	)			(208	)			0.9	%			8.3	%			(568	)			(469	)			21.1	%
Other purchases			(221	)			(246	)			(352	)			-10.2	%			-37.3	%			(606	)			(832	)			-27.2	%
Stock variations			54				(132	)			157				N/A				-65.6	%			(9	)			30				N/A
Total Purchases & Stock Variations			(1,324	)			(1,340	)			(1,206	)			-1.2	%			9.8	%			(3,623	)			(3,481	)			4.1	%
Other operating results, net			(48	)			(26	)			(48	)			84.6	%			0.0	%			(397	)			(50	)			694.0	%
Reversal / (Impairment) of PP&E and inventories write-down			(5	)			9				(21	)			N/A				-76.2	%			4				(26	)			N/A
Operating Costs + Purchases + Impairment of Assets			(4,091	)			(4,229	)			(4,543	)			-3.3	%			-9.9	%			(12,736	)			(12,532	)			1.6	%

Stock variations include price effects by (US$ 4) million in 3Q25, (US$96) million for 2Q25, US$94 million for 3Q24, (US$96) million for 9M25 and (US$64) million for 9M24

OPEX totaled US$1,356 million (-11% q/q), mainly derived from savings associated with the reduced exposure to conventional mature fields, significant ramp-up in efficient shale production and lower costs in dollar terms, partially offset by higher non-cash environmental provisions recorded in Other Upstream costs.

Total Other Costs reached US$1,358 million (+1% q/q), primarily explained by higher depreciation and amortization related to increased shale activity, partially offset by lower oil export duties and royalties from mature fields.

Purchases & Stock Variations amounted to US$1,324 million (-1% q/q). Purchases increased q/q, mostly driven by higher oil purchases to third parties as the result of the reduced exposure to mature fields and higher processing levels at refineries. Stock variations reached a positive charge of US$54 million in 3Q25 (compared to a negative US$132 million in 2Q25), primarily on the back of higher crude oil purchases to third parties to restock inventories and compensate the inventory drawdown recorded in 2Q25.

Other operating net results totaled negative US$48 million (vs. a loss of US$26 million in 2Q25). In 2Q25, the provision of losses related to mature fields were partially offset by the positive result from the sale of mature fields and 49% of Aguada del Chañar block, as well as revaluation of companies. In 3Q25, we recorded lower provision of losses from mature fields.

¹  1 ADR = 1 share. Total issued capital stock amounted to 393,312,793 shares as of Sep-25 (51% Argentina Government; 27% NYSE and 22% ByMA).

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Consolidated Net Income Breakdown Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Operating income / (loss)			552				412				754				34.0	%			-26.8	%			1,156				2,010				-42.5	%
Result from equity interests in associates and joint ventures			32				(6	)			107				N/A				-70.1	%			107				263				-59.3	%
Financial results, net			(245	)			(256	)			(210	)			-4.5	%			16.8	%			(746	)			(753	)			-0.9	%
Net result before tax			339				150				651				126.6	%			-47.9	%			517				1,520				-66.0	%
Income tax			(537	)			(92	)			834				486.0	%			N/A				(667	)			1,157				N/A
Net result			(198	)			58				1,485				N/A				N/A				(150	)			2,677				N/A
Net Income before impairment of assets			328				131				1,499				151.0	%			-78.1	%			467				2,694				-82.6	%

Financial net results recorded a loss of US$245 million, 4.5% below the previous quarter, primarily explained by a decrease in the mark-to-market valuation of sovereign bonds within the cash position, offset by a lower abandonment provision following the exit from mature fields.

Income tax recorded a negative charge of US$537 million, versus a negative charge of US$92 million in 2Q25, mostly reflecting higher non-cash deferred income tax. Consequently, net result totaled a loss of US$198 million.

2. ADJ. EBITDA & CAPEX

2.1 ADJ. EBITDA RECONCILIATION

Reconciliation of Adjusted EBITDA Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Net result			(198	)			58				1,485				N/A				N/A				(150	)			2,677				N/A
Financial results, net			245				256				210				-4.5	%			16.8	%			746				753				-0.9	%
Result from equity interests in associates and joint ventures			(32	)			6				(107	)			N/A				-70.1	%			(107	)			(263	)			-59.3	%
Income tax			537				92				(834	)			486.0	%			N/A				667				(1,157	)			N/A
Unproductive exploratory drillings			—				1				1				N/A				N/A				1				56				-98.2	%
Depreciation & amortization			836				788				674				6.1	%			24.0	%			2,430				1,964				23.7	%
Reversal / (Impairment) of PP&E and inventories write-down			5				(9	)			21				N/A				-76.2	%			(4	)			26				N/A
EBITDA			1,393				1,192				1,450				16.9	%			-3.9	%			3,583				4,056				-11.7	%
Leasing			(88	)			(82	)			(84	)			8.4	%			5.7	%			(255	)			(241	)			5.8	%
Provision for operating optimizations			76				30				—				150.5	%			N/A				106				—				N/A
Result from sale of assets			(17	)			(168	)			—				-90.0	%			N/A				(199	)			—				N/A
Result from changes in fair value of assets held for sale			(4	)			44				—				-110.1	%			N/A				240				—				N/A
Provision for severance indemnities			2				0				—				N/A				N/A				28				—				N/A
Provision for obsolescence of materials and equipment			(11	)			123				—				N/A				N/A				248				—				N/A
Result from revaluation of companies			0				(45	)			—				N/A				N/A				(44	)			—				N/A
Miscellaneous – Mature Fields			6				29				—				-79.2	%			N/A				19				—				N/A
Adjusted EBITDA			1,357				1,124				1,366				20.8	%			-0.7	%			3,725				3,815				-2.3	%

2.2 ADJ. EBITDA & CAPEX BY SEGMENT

By Segment		3Q25				2Q25				Q/Q Δ				3Q24				Y/Y Δ				9M25				9M24				Δ
Adj. EBITDA
Upstream			1,042				770				35	%			784				33	%			2,578				2,430				6	%
Midstream & Downstream			354				439				-19	%			476				-26	%			1,298				1,442				-10	%
LNG & IG			(4	)			(0	)			6623	%			10				N/A				(9	)			(44	)			-80	%
New Energies			52				26				101	%			91				-43	%			116				122				-5	%
Corp			(57	)			(42	)			36	%			(53	)			8	%			(135	)			(107	)			26	%
Eliminations & Others			(30	)			(68	)			-56	%			58				N/A				(122	)			(29	)			329	%
Total Adj. EBITDA			1,357				1,124				21	%			1,366				-1	%			3,726				3,815				-2	%
CAPEX
Upstream			751				864				-13	%			983				-24	%			2,595				2,781				-7	%
Midstream & Downstream			218				246				-11	%			328				-33	%			668				837				-20	%
LNG & IG			9				14				-36	%			3				171	%			26				8				212	%
New Energies			7				8				-7	%			13				-40	%			26				25				5	%
Corp			31				28				13	%			26				20	%			77				70				9	%
Eliminations			—				—				N/A				—				N/A				—				—				N/A
Total CAPEX			1,017				1,160				-12	%			1,353				-25	%			3,391				3,722				-9	%

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3. ANALYSIS OF RESULTS BY SEGMENT

3.1 UPSTREAM

Upstream Financials Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Crude oil			1,323				1,324				1,599				-0.1	%			-17.3	%			4,294				4,726				-9.2	%
Natural gas			611				541				616				12.9	%			-0.8	%			1,546				1,480				4.4	%
Other			33				29				31				11.6	%			5.6	%			90				100				-10.0	%
Revenues			1,967				1,895				2,246				3.8	%			-12.4	%			5,929				6,306				-6.0	%
Depreciation & amortization			(615	)			(588	)			(475	)			4.6	%			29.6	%			(1,805	)			(1,397	)			29.2	%
Lifting cost			(426	)			(611	)			(827	)			-30.3	%			-48.5	%			(1,795	)			(2,238	)			-19.8	%
Royalties			(237	)			(241	)			(291	)			-1.6	%			-18.6	%			(740	)			(825	)			-10.3	%
Other costs			(274	)			(279	)			(299	)			-1.7	%			-8.2	%			(1,117	)			(730	)			53.0	%
Operating income before impairment of assets			415				176				354				135.8	%			17.2	%			472				1,116				-57.7	%
Reversal / (Impairment) of PP&E and inventories write-down			—				—				(21	)			N/A				N/A				—				(21	)			N/A
Operating income / (loss)			415				176				333				135.8	%			24.6	%			472				1,095				-56.9	%
Depreciation & amortization			615				588				475				4.6	%			29.6	%			1,805				1,397				29.2	%
Unproductive exploratory drillings			—				1				1				N/A				N/A				1				56				-98.2	%
Reversal / (Impairment) of PP&E and inventories write-down			—				—				21				N/A				N/A				—				21				N/A
EBITDA			1,030				765				830				34.7	%			24.1	%			2,278				2,569				-11.3	%
Leasing			(42	)			(51	)			(45	)			-19.2	%			-8.4	%			(142	)			(139	)			2.3	%
Provision for operating optimizations			76				30				—				150.5	%			N/A				106				—				N/A
Result from sale of assets			(16	)			(168	)			—				-90.6	%			N/A				(197	)			—				N/A
Result from changes in fair value of assets held for sale			—				44				—				N/A				N/A				244				—				N/A
Provision for severance indemnities			2				—				—				N/A				N/A				28				—				N/A
Provision for obsolescence of materials and equipment			(11	)			123				—				N/A				N/A				248				—				N/A
Miscellaneous – Mature Fields			2				29				—				-92.1	%			N/A				15				—				N/A
Adjusted EBITDA			1042				771				784				35.1	%			32.9	%			2,580				2,430				6.1	%
CAPEX			751				864				983				13.1	%			-23.6	%			2,595				2,781				-6.7	%

Unit Cash Costs Unaudited Figures, in US$/boe		3Q25				2Q25				3Q24				Q/Q Δ				Y/YΔ				9M25				9M24				Y/Y Δ
Lifting Cost			8.8				12.3				16.1				-28.1	%			-45.0	%			12.2				15.1				-19.3	%
Royalties and other taxes			6.0				6.2				7.0				-2.8	%			-14.4	%			6.2				6.9				-9.9	%
Other Costs			4.0				3.4				4.1				17.8	%			-1.9	%			3.6				3.4				6.6	%
Total Cash Costs (US$/boe)			18.8				21.8				27.1				-13.9	%			-30.7	%			22.0				25.4				-13.3	%

Revenues totaled US$1,967 million (+4% q/q), mainly driven by higher seasonal sales of natural gas (+6% price and +6% volume) coupled with increased shale production, partially counterbalanced by lower conventional production.

Lifting costs dropped to US$8.8/BOE (-28% q/q), reflecting the considerable progress in the divestment of mature fields, coupled by shale oil ramp-up. When breaking down our lifting costs by type of operation in 3Q25, our unconventional activities averaged 4.2 US$/BOE, remaining almost flat q/q, while our conventional operations averaged 20.8 US$/BOE, representing a sequential decrease of 23% mainly driven by the evolution of the divestment in mature fields. Lifting cost gross within our shale core hub averaged 4.6 US$/BOE in 3Q25, decreasing 7% q/q, as 2Q25 was affected by higher pulling and maintenance costs.

Royalties amounted to US$237 million (-2% q/q), primarily driven by lower mature fields production, partially offset by shale production ramp-up and higher natural gas prices.

Other costs amounted to US$274 million (-2% q/q), mainly explained by lower one-off costs related to mature fields in 3Q25, partially compensated by the positive results from sale of 49% of Aguada del Chañar booked in 2Q25.

Adj. EBITDA totaled US$1,042 million (+35% q/q), mostly boosted by better lifting costs (exiting mature fields and expanding shale) and higher seasonal sales of natural gas, and to a minor extent, lower operating costs in dollar terms.

CAPEX amounted to US$751 million, from which 94% was allocated to unconventional assets, mostly destined to drilling and workover activities. The sequential 13% decrease is the result of lower costs in dollar terms.

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Unconventional horizontal oil wells recorded again strong metrics, particularly tied-in activities:

In terms of efficiencies within our unconventional operations, we achieved solid operational metrics in terms of drilling and fracking activities. In this sense, we averaged 337 meters/day of drilling speed in our core-hub blocks (+2% q/q), and 279 stages/set-month of fracking speed (+8% q/q).

Upstream Operating data Unaudited Figures		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Net Production Breakdown
Crude Production (Kbbld)			239.8				247.9				255.8				-3.2	%			-6.3	%			252.4				253.4				-0.4	%
Conventional			69.0				101.7				127.7				-32.2	%			-46.0	%			97.1				133.8				-27.4	%
Shale			170.0				145.1				125.7				17.1	%			35.2	%			154.2				117.1				31.7	%
Tight			0.9				1.0				2.5				-10.9	%			-64.4	%			1.1				2.4				-55.0	%
NGL Production (Kbbld)			41.9				48.0				49.5				-12.7	%			-15.3	%			45.7				45.8				-0.1	%
Conventional			11.3				12.5				12.0				-10.0	%			-6.3	%			12.2				11.0				10.5	%
Shale			30.4				35.1				36.5				-13.4	%			-16.7	%			33.1				33.7				-1.7	%
Tight			0.3				0.4				1.0				-38.4	%			-72.9	%			0.5				1.1				-58.9	%
Gas Production (Mm3d)			38.4				39.7				40.3				-3.4	%			-4.8	%			38.5				38.5				-0.1	%
Conventional			8.7				11.1				12.2				-21.0	%			-28.1	%			10.4				12.7				-18.0	%
Shale			26.3				25.0				23.4				4.9	%			12.2	%			24.5				20.8				17.7	%
Tight			3.4				3.6				4.7				-7.1	%			-29.1	%			3.5				5.0				-28.7	%
Total Production (Kboed)			523.1				545.7				558.7				-4.1	%			-6.4	%			540.2				541.3				-0.2	%
Conventional			135.2				183.9				216.1				-26.5	%			-37.4	%			174.8				224.7				-22.2	%
Shale			365.6				337.7				309.5				8.3	%			18.2	%			341.6				281.9				21.2	%
Tight			22.2				24.1				33.2				-7.8	%			-33.0	%			23.8				34.8				-31.5	%
Average realization prices
Crude Oil (USD/bbl)			60.0				59.5				68.3				0.9	%			-12.1	%			62.6				69.1				-9.4	%
Natural Gas (USD/MMBTU)			4.3				4.1				4.5				6.4	%			-3.0	%			3.8				3.8				-1.2	%

Crude oil production averaged 240 kbbl/d (-3% q/q), mainly explained by lower conventional production from mature fields, mostly replaced by the notable ramp-up in shale oil production (+17% q/q), highlighting the increased shale oil production within our core-hub blocks (+12%) and La Angostura Sur (+37%), among others. On an interannual basis, shale oil production recorded an impressive growth rate of 35%, and when excluding the effect of the sale of Aguada del Chañar block, shale oil production would have increased by 43% y/y.

Natural gas production contracted by -3% q/q, primarily explained by lower output from mature fields, slightly offset by increased shale gas production, especially in La Calera and Aguada de la Arena wet gas blocks.

NGLs production also dropped -13% q/q, primarily due to operational issues at La Calera block (normalized in October), and lower contribution from mature fields.

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3.2 MIDSTREAM & DOWNSTREAM

Midstream & Downstream Financials Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Diesel (third parties)			1,467				1,526				1,646				-3.9	%			-10.9	%			4,514				4,873				-7.4	%
Gasoline (third parties)			929				923				1,023				0.6	%			-9.1	%			2,890				2,991				-3.4	%
Other domestic market			706				611				794				15.6	%			-11.0	%			1,958				2,060				-5.0	%
Export market			619				680				705				-9.0	%			-12.2	%			2,019				2,027				-0.4	%
Revenues			3,721				3,741				4,168				-0.5	%			-10.7	%			11,380				11,952				-4.8	%
Depreciation & amortization			(185	)			(162	)			(164	)			14.1	%			12.8	%			(512	)			(469	)			9.1	%
OPEX Downstream			(520	)			(527	)			(572	)			-1.3	%			-9.1	%			(1,582	)			(1,570	)			0.8	%
Fuels imports (including jet fuel - third parties)			(35	)			(53	)			(98	)			-33.2	%			-64.0	%			(147	)			(197	)			-25.3	%
Crude oil purchases (intersegment + third parties)			(2,012	)			(1,765	)			(2,070	)			14.0	%			-2.8	%			(5,908	)			(6,041	)			-2.2	%
Biofuel purchases (third parties)			(208	)			(244	)			(233	)			-14.8	%			-10.9	%			(678	)			(698	)			-3.0	%
Agro products purchases (third parties)			(226	)			(224	)			(208	)			0.9	%			8.3	%			(568	)			(469	)			21.1	%
Stock variations			35				(114	)			17				N/A				104.0	%			25				125				-80.4	%
Other			(412	)			(366	)			(544	)			12.5	%			-24.3	%			(1,184	)			(1,477	)			-19.8	%
Operating income / (loss) before impairment of assets			158				286				295				-44.8	%			-46.4	%			826				1,156				-28.5	%
Reversal / (Impairment) of PP&E			—				—				—				N/A				N/A				—				—				N/A
Operating income / (loss)			158				286				295				-44.8	%			-46.4	%			826				1,156				-28.5	%
Depreciation & amortization			185				162				164				14.1	%			12.8	%			512				469				9.1	%
Reversal / (Impairment) of PP&E			—				—				—				N/A				N/A				—				—				N/A
EBITDA			343				448				459				-23.5	%			-25.3	%			1,338				1,625				-17.7	%
Leasing			(46	)			(29	)			(38	)			58.9	%			19.2	%			(110	)			(102	)			7.4	%
Result from revaluation of compañíes			—				(44	)			—				N/A				N/A				(44	)			—				N/A
Adjusted EBITDA			296				376				421				-21.2	%			-29.6	%			1,184				1,523				-22.2	%
Inventories price effect of oil products			(58	)			(63	)			(55	)			-7.5	%			5.0	%			(114	)			80				N/A
Adjusted EBITDA excl. inventories price effect of oil products			354				439				476				-19.2	%			-25.6	%			1,298				1,442				-10.0	%
CAPEX			218				246				328				-11.3	%			-33.5	%			668				837				-20.2	%

Stock variations include price effects by (US$54) million in 3Q24, (US$48) million for 3Q25, (US$60) million for 2Q25, (US$100) million for 9M25 and US$86 million for 9M24.

Revenues totaled US$3.7 billion (-1% q/q) mainly as a result of lower prices of local fuels and the basket of refined products other than gasoline and diesel partially compensated by an increase in volumes dispatched of diesel and gasoline in the local market, higher exports of gasoline and jet fuel to neighboring countries and greater demand of fertilizers in the local market.

OPEX Downstream amounted to US$520 million (-1% q/q), mainly due to lower costs in dollar terms and lower maintenance costs as the 2Q25 was affected by programmed stoppage in La Plata refinery.

Fuel imports reached US$35 million (-33% q/q), driven by higher production of gasoline and diesel in our refineries. In that sense, in 3Q25, fuel imports remained at very low levels, representing only 1% of total fuel sales, compared to 3% in 2Q25 and 4% in 3Q24.

Crude oil purchases (intersegment + third parties) amounted to US$2,012 million (+14% q/q), driven by increased processing levels, given the record achieved in 3Q25, while 2Q25 was affected by the maintenance stoppage at La Plata Refinery.

Biofuel purchases decreased by 15% q/q, where purchases of biodiesel declined 22%, and purchases of bioethanol dropped 6%. Biodiesel purchases contraction was mainly the result of the lower blend in diesel sales, the latter due to supply constraints in the local market, while bioethanol purchases decreased mainly as a result of lower prices, partially offset by higher volumes aligned to greater gasoline demand.

Agro products purchases (+1% q/q): mostly in line with higher local sales of fertilizers, partially offset by lower exports of grain and flour.

Stock variations totaled a positive charge of US$35 million (vs. a negative charge of US$114 million in 2Q25), primarily on the back of higher crude oil purchases to third parties to restock inventories and compensate the inventory drawdown recorded in 2Q25.

Other costs increased by +12% q/q, mostly due to the positive result from the revaluation of Loma Campana – Lago Pellegrini pipeline booked in 2Q25 after completing its acquisition, slightly offset by lower costs in dollar terms.

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Adj. EBITDA, excluding inventories price effect of oil products, totaled US$354 million (-19% q/q), mainly driven by lower local fuel prices, partially offset by higher processing levels and lower fuel imports.

Adj. EBITDA of the Refining & Marketing business, in unit terms, amounted to US$5.9/bbl, below the Adjusted EBITDA recorded in 2Q25 of US$11.9/bbl.

CAPEX amounted to US$218 million in 3Q25, where 68% was allocated to refining, 14% to midstream (O&G), 13% to logistics and 5% others. The sequential drop of 11% is mostly driven by lower costs in dollar terms.

In our refineries, CAPEX was mostly allocated to 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 by June 2026.

• Revamping of topping units at Luján de Cuyo refinery. We continue making progress in the reconditioning of the refinery to process lighter Vaca Muerta’s shale oil, expected to be in place in 1H26.

In our midstream oil business unit, our affiliate VMOS continued moving forward with its project:

• VMOS: (construction progress ~35% as of Sep-25) during the quarter, works related to the oil pipeline routes and trench excavation were completed, on track with the plan. Moreover, in early Nov-25 welding works for the 440 km oil pipeline were completed.

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 its current capacity, and improving the treatment of associated gas. The revamping is expected to be operational in 1Q26.

• South Hub gathering project to expand gas processing capacity at Sierra Barrosa treatment plants. The first phase was completed in 2024, while second phase is expected to be completed in 2027.

• North Hub gathering project, consistent in the construction of a new gas pipeline connecting Narambuena and Bajo del Toro blocks with El Portón Industrial Complex. Early start-up is expected by 2Q26 to become fully operational in 2027.

Midstream & Downstream Operating data Unaudited Figures		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Crude processed (Kbbld)			326.2				301.4				298.3				8.2	%			9.3	%			315.2				299.5				5.2	%
Refinery utilization (%)			96.5	%			89.2	%			88.3	%			735bps				824bps				93.3	%			88.6	%			464bps
Nominal capacity at 337.94 Kbbl/d since 1Q24.
Sales volume to third parties (YPF stand alone)
Sales of refined products (Km3)			4,930				4,727				4,772				4.3	%			3.3	%			14,448				14,097				2.5	%
Total domestic market			4,513				4,328				4,294				4.3	%			5.1	%			13,053				12,600				3.6	%
of which Gasoline			1,501				1,413				1,421				6.3	%			5.7	%			4,394				4,282				2.6	%
of which Diesel			2,154				2,119				2,029				1.6	%			6.1	%			6,198				6,088				1.8	%
Total export market			417				398				478				4.6	%			-12.7	%			1,395				1,497				-6.8	%
Sales of petrochemical products (Ktn)			131				145				168				-9.8	%			-22.3	%			385				471				-18.2	%
Domestic market			65				52				91				24.5	%			-27.9	%			176				231				-23.5	%
Export market			65				92				78				-29.2	%			-15.7	%			209				240				-13.1	%
Sales of fertilizers, grain and flours (Ktn)			535				559				535				-4.2	%			0.0	%			1,489				1,214				22.7	%
Domestic market			196				124				327				58.3	%			-40.0	%			403				664				-39.3	%
Export market			339				434				208				-22.1	%			62.9	%			1,086				549				97.8	%
Net average prices
Gasoline (USD/m3) (domestic market)			567				596				657				-4.8	%			-13.6	%			601				639				-6.0	%
Diesel (USD/m3) (domestic market)			637				672				758				-5.3	%			-16.0	%			682				755				-9.7	%
Petrochemical & others refined products (USD/bbl)			81				72				70				11.3	%			16.0	%			76				71				7.0	%

Net Average domestic prices for gasoline and diesel are net of taxes, commissions, commercial bonuses and freights.

Crude oil processed averaged 326 kbbl/d (+8% q/q), reaching a record-high since 2009 coupled with an utilization rate of 97%, mainly boosted by the solid performance recorded in La Plata refinery in 3Q25, which processed 196 kbbl/d (+14% q/q), while 2Q25 was affected by programmed maintenances.

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Domestic fuels sales volumes reached 3,655 km3, growing +3% q/q (gasoline +6% and diesel +2%), on the back of higher market share in the retail and industrial segments, slightly offset by lower seasonal diesel sales to the agricultural segment.

Petrochemicals sales volumes decreased by 10% q/q, mainly due to lower exports of methanol, partially offset by higher local demand. Fertilizers’ local sales volume grew by 64% q/q, primary on the back of increased market share and presales. While grain and flour sales volumes dropped 22% q/q, mostly due to lower seasonal exports, but continued boosted by the temporary elimination of export duties until Oct-25.

Net average fuels prices in local market measured in dollar terms dropped 5% q/q, mainly due to a very volatile local scenario, representing a temporary gap against import parity of around 10%, which started normalizing during October.

Prices for petrochemical & other refined products increased by 11% q/q, mainly due to upward trend in international prices of petrochemical and certain refined products, primarily lubricant bases and coal.

3.3 LNG & INTEGRATED GAS

LNG & Integrated Gas Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Natural gas (intersegment + third parties)			634				539				635				17.5	%			-0.2	%			1,556				1,511				3.0	%
Other			28				26				18				10.8	%			56.5	%			71				55				27.9	%
Revenues			662				565				653				17.2	%			1.4	%			1,627				1,566				3.9	%
Depreciation & amortization			(2	)			(0	)			(0	)			476.3	%			574.6	%			(3	)			(1	)			228.0	%
Natural gas purchases (intersegment + third parties)			(624	)			(532	)			(624	)			17.3	%			-0.1	%			(1,561	)			(1,494	)			4.5	%
Operating cost & Other			(42	)			(33	)			(18	)			28.4	%			129.8	%			(74	)			(116	)			-36.5	%
Operating income before impairment of assets			(6	)			—				10				N/A				N/A				(11	)			(45	)			-75.6	%
Reversal / (Impairment) of PP&E			—				—				—				N/A				N/A				—				—				N/A
Operating income			(6	)			—				10				N/A				N/A				(11	)			(45	)			-75.6	%
Depreciation & amortization			2				0				0				476.3	%			574.6	%			3				1				228.0	%
EBITDA			(4	)			0				10				N/A				N/A				(8	)			(44	)			-82.5	%
Leasing			(0	)			(0	)			—				-33.3	%			N/A				(1	)			—				N/A
Adjusted EBITDA			(4	)			(0	)			10				6623.1	%			N/A				(9	)			(44	)			-79.6	%
CAPEX			9				14				3				-35.7	%			171.1	%			26				8				212.5	%

Adj. EBITDA totaled negative US$4 million, compared to slightly negative US$0.1 million in 2Q25. In 3Q25 natural gas sales grew sequentially due to higher winter seasonal demand, in line with the increase in natural gas purchases. However, operating costs increased against the previous quarter mostly driven by higher activity related to Argentina LNG Project.

CAPEX amounted to US$9 million in 3Q25, mostly allocated to the Argentina LNG Project, which continued progressing during the quarter throughout its 3 phases. Regarding phase 3, in October, YPF and ENI signed a technical FID, targeting a project with a total capacity of ~12 MTPA, expandable to ~18 MTPA, and in November, ADNOC signed a preliminary framework agreement with YPF and ENI, aiming to join the Argentina LNG Project.

3.4 NEW ENERGIES

New Energies Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/YΔ				9M25				9M24				Y/YΔ
Natural gas retail (third parties)			201				188				299				7.2	%			-32.8	%			536				591				-9.3	%
Other			33				41				55				-20.4	%			-40.0	%			119				106				12.3	%
Revenues			234				229				354				2.2	%			-33.9	%			655				697				-6.0	%
Depreciation & amortization			(9	)			(11	)			(12	)			-16.9	%			-24.2	%			(34	)			(34	)			-0.1	%
Natural gas purchases (intersegment + third parties)			(105	)			(103	)			(161	)			2.8	%			-34.4	%			(265	)			(320	)			-17.2	%
Operating cost & Other			(77	)			(101	)			(103	)			-23.9	%			-25.3	%			(274	)			(254	)			7.6	%
Operating income before impairment of assets			43				15				79				186.7	%			-45.6	%			82				88				-6.8	%
Reversal / (Impairment) of PP&E and inventories write-down			(5	)			9				—				N/A				N/A				4				(5	)			N/A
Operating income			38				24				79				58.3	%			-51.9	%			86				83				3.6	%
Depreciation & amortization			9				11				12				-16.9	%			-24.2	%			34				34				-0.1	%
Reversal / (Impairment) of PP&E and inventories write-down			5				(9	)			—				N/A				N/A				(4	)			5				N/A
EBITDA			52				26				91				101.3	%			-42.8	%			116				122				-4.9	%
Leasing			—				—				—				N/A				N/A				—				—				N/A
Adjusted EBITDA			52				26				91				101.3	%			-42.8	%			116				122				-4.9	%
CAPEX			7				8				13				-6.7	%			-40.2	%			26				25				4.5	%

Page 9/14

Adj. EBITDA totaled US$52 million, an improvement of $27 million sequentially, almost entirely attributable to Metrogas subsidiary, as a result of higher sales to residential customers due to increased winter demand, partially offset by lower price in dollar terms.

4. LIQUIDITY AND SOURCES OF CAPITAL

4.1 CASH FLOW SUMMARY

Despite 3Q25 adjusted EBITDA surpassed CAPEX deployment and regular interest payment, free cash flow reached a negative US$759 million, mainly due to the acquisition of shale assets from Total Austral S.A. for -US$523 million and a negative working capital of -US$359 million mostly associated with the discontinued operations in our mature fields, income tax payment from our subsidiaries and longer collection days from natural gas clients and Plan Gas program that started to normalize during October.

Excluding the M&A transaction with Total and one-off items related to mature fields, negative free cash flow proforma would have been -US$172 million.

In terms of liquidity, our cash and short-term investments slightly increased to US$1,016 million by the end of September 2025 (+0.5% q/q).

Notes: (1) Approximation of cash flow evolution, highlighting key figures. Cash & equivalents include Argentine sovereign bonds and Treasury notes. (2) Refers to the acquisition of La Escalonada & Rincón la Ceniza blocks. (3) Others mainly include mature fields one-off items for a total of (-13): operating optimizations (-11), severance indemnities (-3), additions of assets held for sale (-3), and +4 of collections for sale of assets. Moreover, considers payment of leasing, dividend collections & contribution to affiliates. (4) Others include mainly FX differences and net collection for sale of financial assets.

4.2 NET DEBT

Net debt breakdown Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ
Short-term debt			2,653				2,252				1,832				17.8	%
Long-term debt			7,958				7,592				6,869				4.8	%
Total debt			10,611				9,844				8,701				7.8	%
Avg. Interest rate for US$-debt			6.7	%			6.6	%			6.5	%
% of debt in USD			98.7	%			99.7	%			99.3	%
Cash + short term investments			1,016				1,011				1,195				0.5	%
% of liquidity dollarized			70.5	%			67.2	%			81.8	%
Net debt			9,595				8,833				7,506				8.6	%

Average interest rates for US$ debt refer to YPF on a stand-alone basis.

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As of September 30, 2025, YPF’s consolidated net debt totaled US$9,595 million, increasing by US$762 million q/q. The higher net debt resulted in an increase in the net leverage ratio from 1.9x in 2Q25 to 2.1x in 3Q25, mainly due to the financing of shale blocks acquired from Total. Excluding this M&A transaction, the net leverage ratio proforma would have amounted to 1.9x.

In terms of financing, during 3Q25 YPF tapped the local capital market, issuing three new bonds:

1) US$-MEP bond for US$250 million, with a 2-year tenor at 7.5% rate

2) US$-MEP bond for US$51 million with a 3-year tenor at 7.5% rate

3) US$-Cable bond for US$225 million with a 5-year tenor (initial issuance of US$167 million at 8.75% rate, followed by a reopening of US$58 million at 8.25% yield)

In addition, by the end of September, YPF secured a US$300 million international bridge loan, which, combined with the US$-Cable issuances, allowed to finance the recent acquisition of Total’s shale assets.

After 3Q25, we issued in the local market a US$-MEP bond for US$99 million, with a 15-months tenor at 6%. Moreover, in October, we reopened the syndicated cross-border loan market by signing a US$700 million export-backed facility with 10 international banks. The loan has a 3-year tenor and was structured as a prefunding strategy for refinancing local maturities coming due in 1Q26. Lastly, in late October, we successfully returned to the international capital market by re-opening our 2031 international bond for US$500 million at 8.25% yield. The proceeds will be used to fully repay the bridge loan for the acquisition of Total Austral’s shale assets and to finance YPF’s investment plan.

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 last quarter of 2025, the Company faces US$479 million of manageable maturities, mostly local: US$365 million of short-term trade facilities with local banks; US$60 million of export-backed bond amortizations; and US$54 million of local bank loans. In addition, the Company decided to fully redeem in Nov-25 the last two amortizations of the Secured notes due 2026 (a total of US$120 million).

The following chart shows our consolidated principal debt maturity profile as of September 30, 2025:

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5. TABLES

5.1 CONSOLIDATED BALANCE SHEET

Consolidated Balance Sheet Unaudited Figures		30-Sep-25				31-Dec-24
Non-current Assets
Intangible assets			1,056				491
Properties, plant and equipment			19,627				18,736
Right-of-use assets			588				743
Investments in associates and joint ventures			1,917				1,960
Deferred income tax assets, net			4				330
Other receivables			774				337
Trade receivables			1				1
Total Non-current Assets			23,967				22,598
Current Assets
Assets held for disposal			489				1,537
Inventories			1,529				1,546
Contract assets			7				30
Other receivables			671				552
Trade receivables			1,890				1,620
Investment in financial assets			217				390
Cash and cash equivalents			799				1,118
Total Current Assets			5,602				6,793
Total Assets			29,569				29,391
Total Shareholders´ Equity			11,634				11,870
Non-current Liabilities
Provisions			1,123				1,084
Deferred income tax liabilities, net			389				90
Contract liabilities			166				114
Income tax liability			1				2
Salaries and social security			26				34
Lease liabilities			314				406
Loans			7,958				7,035
Other liabilities			452				74
Accounts payable			6				6
Total non-current Liabilities			10,435				8,845
Current Liabilities
Liabilities directly associated with assets held for sale			914				2,136
Provisions			132				116
Contract liabilities			117				73
Income tax liability			20				126
Taxes payable			248				247
Salaries and social security			326				412
Lease liabilities			311				370
Loans			2,653				1,907
Other liabilities			372				410
Accounts payable			2,407				2,879
Total Current Liabilities			7,500				8,676
Total Liabilities			17,935				17,521
Total Liabilities and Shareholders’ Equity			29,569				29,391

Note: Information reported in accordance with International Financial Reporting Standards (IFRS).

Page 12/14

5.2 CONSOLIDATED INCOME STATEMENT

Income Statement Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/YΔ				9M25				9M24				Y/Y Δ
Revenues			4,643				4,641				5,297				0.0	%			-12.3	%			13,892				14,542				-4.5	%
Costs			(3,319	)			(3,468	)			(3,678	)			-4.3	%			-9.8	%			(10,116	)			(10,154	)			-0.4	%
Gross profit			1,324				1,173				1,619				12.9	%			-18.2	%			3,776				4,388				-13.9	%
Selling expenses			(495	)			(535	)			(552	)			-7.5	%			-10.3	%			(1,558	)			(1,596	)			-2.4	%
Administrative expenses			(207	)			(188	)			(224	)			10.1	%			-7.6	%			(601	)			(575	)			4.5	%
Exploration expenses			(17	)			(21	)			(20	)			-19.0	%			-15.0	%			(68	)			(131	)			-48.1	%
Reversal / (Impairment) of PP&E and inventories write-down			(5	)			9				(21	)			N/A				-76.2	%			4				(26	)			N/A
Other net operating results, net			(48	)			(26	)			(48	)			84.6	%			0.0	%			(397	)			(50	)			694.0	%
Operating income			552				412				754				34.0	%			-26.8	%			1,156				2,010				-42.5	%
Income of interests in companies and joint ventures			32				(6	)			107				N/A				-70.1	%			107				263				-59.3	%
Financial Income			28				28				19				0.0	%			47.4	%			72				87				-17.2	%
Financial Cost			(257	)			(279	)			(267	)			-7.9	%			-3.7	%			(821	)			(911	)			-9.9	%
Other financial results			(16	)			(5	)			38				197.4	%			N/A				3				71				-95.8	%
Net Financial results			(245	)			(256	)			(210	)			-4.5	%			16.8	%			(746	)			(753	)			-0.9	%
Net profit before income tax			339				150				651				126.6	%			-47.9	%			517				1,520				-66.0	%
Income tax			(537	)			(92	)			834				486.0	%			N/A				(667	)			1,157				N/A
Net (loss) / profit for the period			(198	)			58				1,485				N/A				N/A				(150	)			2,677				N/A
Net (loss) / profit for the period attributable to:
Shareholders of the parent company			(206	)			50				1,470				N/A				N/A				(172	)			2,638				N/A
Non-controlling interest			8				8				15				0.0	%			-46.7	%			22				39				-43.6	%
Earnings per share attributable to shareholders of the parent company (basic and diluted)			(0.53	)			0.13				3.75				N/A				N/A				(0.44	)			6.73				N/A

5.3 SUMMARY OF CONSOLIDATED CASHFLOW STATEMENT

Summary Consolidated Cash Flow Unaudited Figures, in US$ million		3Q25				2Q25				3Q24				Q/Q Δ				Y/Y Δ				9M25				9M24				Y/Y Δ
Cash BoP			774				938				1,041				-17.5	%			-25.6	%			1,118				1,123				-0.4	%
Net cash flow from operating activities			1,225				1,146				1,695				6.9	%			-27.7	%			3,221				4,206				-23.4	%
Net cash flow from investing activities			(1,662	)			(1,258	)			(1,439	)			32.1	%			15.5	%			(4,303	)			(4,111	)			4.7	%
Net cash flow from financing activities			497				20				(398	)			2385.0	%			N/A				871				(292	)			N/A
FX adjustments & other			(35	)			(72	)			(22	)			-51.4	%			61.8	%			(108	)			(49	)			122.1	%
Cash EoP			799				774				877				3.2	%			-8.9	%			799				877				-8.9	%
Investment in financial assets			217				237				318				-8.4	%			-31.8	%			217				318				-31.8	%
Cash + short-term investments EoP			1,016				1,011				1,195				0.5	%			-15.0	%			1,016				1,195				-15.0	%
FCF			(759	)			(365	)			(173	)			107.9	%			338.7	%			(2,081	)			(824	)			152.5	%

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 +30% of the country’s oil and gas, and we are the largest shale producer in Vaca Muerta, in process of divestment of conventional mature fields; (ii) in the downstream, we operate 4 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.

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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.

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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: November 7, 2025				By:		/s/ Margarita Chun
				Name:		Margarita Chun
				Title:		Market Relations Officer

FAQ

What were YPF (YPF) Q3 2025 headline financials?

Revenue was US$4,643 million, Adjusted EBITDA US$1,357 million, and net loss US$198 million.

How did YPF’s production and costs change in Q3 2025?

Shale oil averaged 170 kbbl/d (+17% q/q); total production was 523.1 kboe/d (−4% q/q). Lifting cost fell to US$8.8/boe.

What drove YPF’s free cash flow and leverage in Q3 2025?

FCF was −US$759 million, mainly from a US$523 million shale acquisition and working capital. Net debt rose to US$9,595 million (net leverage 2.1x).

How did downstream operations perform for YPF in Q3 2025?

Refinery runs hit 326 kbbl/d with 97% utilization; downstream Adjusted EBITDA was US$5.9/bbl, down from US$11.9/bbl in Q2.

What financing steps did YPF take after Q3 2025?

YPF signed a US$700 million export‑backed facility and reopened its 2031 bond for US$500 million at an 8.25% yield.

How much did YPF invest in Q3 2025 and where?

CAPEX was US$1,017 million, with roughly 70% allocated to unconventional assets focused on Vaca Muerta.