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
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
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
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	%
Total Domestic Market			3,922				3,852				4,197				1.8	%			-6.6	%			7,774				7,844				-0.9	%
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	%
Total Export Market			719				756				738				-4.9	%			-2.5	%			1,475				1,401				5.2	%
Total Revenues			4,641				4,608				4,935				0.7	%			-6.0	%			9,249				9,245				0.0	%

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	%
Total OPEX			(1,529	)			(1,744	)			(1,842	)			-12.3	%			-17.0	%			(3,273	)			(3,222	)			1.6	%
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	%
Total Other Costs			(1,343	)			(1,390	)			(1,303	)			-3.4	%			3.1	%			(2,733	)			(2,485	)			10.0	%
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	%
Total Purchases & Stock Variations			(1,340	)			(959	)			(1,187	)			39.7	%			12.9	%			(2,299	)			(2,275	)			1.1	%
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
Operating Costs + Purchases + Impairment of Assets			(4,229	)			(4,416	)			(4,345	)			-4.2	%			-2.7	%			(8,645	)			(7,989	)			8.2	%

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	%
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	%
Net result before tax			119				17				456				600.0	%			-73.9	%			136				992				-86.3	%
Income tax			(61	)			(27	)			79				125.9	%			N/A				(88	)			200				N/A
Net result			58				(10	)			535				N/A				-89.2	%			48				1,192				-96.0	%
Net Income before impairment of assets			52				(10	)			538				N/A				-90.3	%			42				1,195				-96.5	%

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
EBITDA			1,192				998				1,282				19.4	%			-7.0	%			2,190				2,606				-16.0	%
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
Adjusted EBITDA			1,124				1,245				1,204				-9.7	%			-6.7	%			2,368				2,449				-3.3	%

2.2 ADJ. EBITDA & CAPEX BY SEGMENT

 

By Segment		2Q25				1Q25				Q/Q Δ				2Q24				Y/Y Δ				1H25				1H24				Δ
Adj. EBITDA
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	%
Total Adj. EBITDA			1,124				1,245				-10	%			1,204				-7	%			2,369				2,449				-3	%
CAPEX
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
Total CAPEX			1,160				1,214				-5	%			1,200				-3	%			2,374				2,369				0	%

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	%
Revenues			1,895				2,067				2,113				-8.3	%			-10.3	%			3,962				4,060				-2.4	%
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	%
Operating income before impairment of assets			176				(119	)			362				N/A				-51.4	%			57				762				-92.5	%
Reversal / (Impairment) of PP&E			—				—				—				N/A				N/A				—				—				N/A
Operating income / (loss)			176				(119	)			362				N/A				-51.4	%			57				762				-92.5	%
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
EBITDA			765				483				860				58.2	%			-11.1	%			1,248				1,739				-28.2	%
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
Adjusted EBITDA			771				766				816				0.6	%			-5.5	%			1,538				1,646				-6.6	%
CAPEX			864				979				863				-11.7	%			0.1	%			1,843				1,798				2.5	%

 

Unit Cash Costs Unaudited Figures, in US$/boe		2Q25				1Q25				2Q24				Q/Q Δ				Y/Y Δ				1H25				1H24				Y/Y Δ
Lifting Cost			12.3				15.3				16.2				-19.3	%			-23.9	%			13.8				14.6				-5.3	%
Royalties and other taxes			6.2				6.6				7.2				-6.8	%			-14.0	%			6.4				6.9				-7.6	%
Other Costs			3.4				3.4				3.5				-0.8	%			-3.1	%			3.4				3.0				13.2	%
Total Cash Costs (US$/boe)			21.8				25.3				26.8				-13.5	%			-18.5	%			23.6				24.4				-3.5	%

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.

 

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