SEC Form 6-K filed by YPF Sociedad Anonima

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.

 

Page 2/14

 

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).

 

Page 3/14

 

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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