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 May 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 May 7, 2025.

 

1Q25 EARNINGS WEBCAST PRESENTATION Webcast on May 8, 2025 10:00 am ET / 11:00 am BAT Follow the presentation via website: CLICK HERE YPF YPF S.A. CONSOLIDATED RESULTS INVESTOR RELATIONS CENTER https://investors.ypf.com Inversoresypf@ypf.com Margarita.chun@ypf.com IR TEAM MARGARITA CHUN –IR MANAGER VALENTINA LÓPEZ –IR CHRISTIAN GONZÁLEZ –IR

 

MAIN HIGHLIGHTS OF 1Q25

 

KPI		1Q25				4Q24				Q/Q Δ				1Q24				Y/Y Δ
Financial
Revenues			4,608				4,751				-3	%			4,310				7	%
Adjusted EBITDA			1,245				839				48	%			1,245				0	%
Net Result			(10	)			(284	)			-96	%			657				N/A
CAPEX			1,214				1,320				-8	%			1,169				4	%
FCF			(957	)			64				N/A				(394	)			143	%
Net Debt			8,336				7,434				12	%			7,200				16	%
Net Leverage Ratio (x)			1.8				1.6				12	%			1.7				6	%
Upstream
Hydrocarbon Production (Kboe/d)			552.1				520.6				6	%			526.0				5	%
Crude Oil (Kbbl/d)			269.9				269.8				0	%			255.5				6	%
Natural Gas (Mm3/d)			37.3				34.3				9	%			36.4				3	%
NGL (Kbbl/d)			47.3				35.2				34	%			41.8				13	%
Crude Oil Price (US$/bbl)			67.9				65.7				3	%			68.3				-1	%
Natural Gas Price (US$/MBTU)			3.0				3.1				-6	%			3.0				0	%
Crude Oil Exports (Kbbl/d)			36.4				40.8				-11	%			27.1				34	%
Shale Oil Production (Kbbl/d)			147.3				138.1				7	%			112.3				31	%
Total Lifting Cost (US$/boe)			15.3				17.3				-12	%			12.9				18	%
Core-Hub Lifting Cost (US$/boe)			4.6				4.2				11	%			3.3				41	%
Midstream & Dw
Crude Processed (Kbbl/d)			318.0				304.1				5	%			301.1				6	%
Refineries’ Utilization Rate (%)			94	%			90	%			5	%			89	%			6	%
Local Fuels Volume Sold (Km3)			3,405				3,577				-5	%			3,489				-2	%
Local Fuels Net Price (US$/m3)			697				685				2	%			691				1	%
Imported Fuels (Km3)			78				44				78	%			142				-45	%
R&M Adj. EBITDA (US$/bbl)			14.3				11.2				28	%			18.5				-22	%

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$1,245 million (+48% q/q), mostly due to higher prices of fuels and other refined products related to Brent, and OPEX saving from certain mature fields already divested, coupled with the increased value of inventories and processing level of our refineries, ahead of upcoming maintenance stoppage. Also, 4Q24 was affected by an environmental provision, as indicated in that period. All of them were partially offset by a slightly higher cost of oil purchases to third parties.

Interannually, adjusted EBITDA was essentially flat, mainly because the higher shale production and local fuel prices, combined with increased processing level in 1Q25, were offset by a reduced OPEX in 1Q24, impacted by the discrete devaluation of mid-December 2023 (partially counterbalanced by lower value of inventories due to the same devaluation).

Excluding mature fields, 1Q25 proxy adjusted EBITDA would have been US$1,351 million.

CAPEX was US$1,214 million, being -8% q/q mainly due to higher CAPEX deployed in Downstream during 4Q24 (revamping works in our refineries and seasonality), while +4% y/y primarily boosted by shale expansion. 75% was concentrated on unconventional activities (mostly shale), increasing considerably from 65% in 4Q24.

Shale oil production averaged 147 kbbl/d (+7% q/q and 31% y/y), representing 55% of our total oil production (4Q24: 51% and 1Q24: 44%). Oil exports reached 36 kbbl/d, being -11% q/q to deliver more own oil to La Plata refinery, while +34% y/y driven by shale oil expansion.

Progress on our main projects:

 

•

Mature Fields Exit Program1 (50 blocks): in early April we signed a MoU with the governor of Santa Cruz Province to move forward with the transfer of the 10 conventional blocks that we operate in that province. From a total of 50 blocks: 11 blocks are divested, 23 blocks in the final stage and 16 blocks in progress.

 

•

VMOS new oil export pipeline (~550 kbbl/d by 1H27, ~US$3 billion CAPEX): YPF holds the largest stake among the initial shippers (27% = 120/445 kbbl/d). Construction started in Jan-25, now working on the oil pipeline routes and trench excavation. We are targeting Project Finance (70% debt and 30% equity).

 

•

Argentina LNG: in early May, the SPV for Argentina LNG 1, Southern Energy, obtained the FID approval for a 20-year bareboat charter agreement for 2.45 MTPA FLNG Hilli Episeyo (COD expected by 2027), and added a second agreement for 3.5 MTPA FLNG MKII (COD expected by 2028), subject to FID approval, estimated in 2H25. YPF owns a 25% equity stake in Southern Energy. On the other hand, YPF signed a MoU with Eni, a strategic partner to develop Argentina LNG 3 (~12 MTPA).

1	2023 conventional lifting cost was ~US$25/BOE, while shale lifting cost was ~US$5/BOE. Also, 2023 conventional mature fields capex was ~US$800 million.

 

Page 4/16

 

Buenos Aires, May 7, 2025 – YPF (BYMA: YPFD | NYSE: YPF²). 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 1Q25

 

Consolidated Revenues Breakdown Unaudited Figures, in US$ million		1Q25				4Q24				1Q24				Q/Q Δ				Y/Y Δ
Diesel			1,521				1,581				1,556				-3.8	%			-2.2	%
Gasoline			1,037				1,022				1,022				1.4	%			1.5	%
Natural gas as producers (third parties)			306				258				278				18.6	%			10.3	%
Other			988				1,117				791				-11.6	%			24.9	%
Total Domestic Market			3,852				3,979				3,646				-3.2	%			5.6	%
Jet fuel			94				105				154				-10.0	%			-38.9	%
Grain and flours			133				131				27				1.4	%			391.4	%
Crude oil			240				262				189				-8.5	%			27.0	%
Petchem & Other			289				274				294				5.2	%			-1.8	%
Total Export Market			756				772				664				-2.2	%			13.9	%
Total Revenues			4,608				4,751				4,310				-3.0	%			6.9	%

Net Revenues amounted to US$4,608 million (-3% q/q), mainly derived from off-peak seasonal local demand of diesel (especially in retail and agribusiness) and fertilizers, as well as decreased oil export volumes (but higher own oil processed in our refineries), partially offset by increased local fuel prices and higher seasonal demand of natural gas from power plants.

 

Unaudited Figures, in US$ million		1Q25				4Q24				1Q24				Q/Q Δ				Y/Y Δ
Lifting cost			(758	)			(828	)			(617	)			-8.5	%			22.8	%
Other Upstream			(147	)			(200	)			(112	)			-26.5	%			31.8	%
OPEX Downstream			(535	)			(573	)			(439	)			-6.6	%			21.9	%
Otros Midstream & Downstream			(55	)			(131	)			(48	)			-57.7	%			15.4	%
LNG & IG, New Energies, Corp. & Other			(249	)			(305	)			(164	)			-18.2	%			51.5	%
Total OPEX			(1,744	)			(2,036	)			(1,380	)			-14.3	%			26.4	%
Depreciation & Amortization			(806	)			(795	)			(652	)			1.4	%			23.6	%
Royalties			(265	)			(261	)			(258	)			1.8	%			2.9	%
Other costs			(319	)			(392	)			(272	)			-18.8	%			17.1	%
Total Other Costs			(1,390	)			(1,448	)			(1,182	)			-4.0	%			17.6	%
Fuels imports (including jet fuel)			(59	)			(28	)			(99	)			113.2	%			-40.5	%
Crude oil purchases to third parties			(485	)			(440	)			(375	)			10.3	%			29.6	%
Biofuel purchases			(226	)			(212	)			(242	)			6.5	%			-6.6	%
Agro products purchases			(119	)			(133	)			(70	)			-10.8	%			68.6	%
Other purchases			(139	)			(206	)			(178	)			-32.3	%			-21.5	%
Stock variations			69				(157	)			(125	)			N/A				N/A
Total Purchases & Stock Variations			(959	)			(1,176	)			(1,088	)			-18.4	%			-11.9	%
Other operating results, net			(323	)			(559	)			6				-42.2	%			N/A
Impairment of PP&E and inventories write-down			—				(61	)			—				N/A				N/A
Operating Costs + Purchases + Impairment of Assets			(4,416	)			(5,280	)			(3,644	)			-16.4	%			21.2	%

Stock variations include price effects by US$ 5 million in 1Q25, (US$47) million for 4Q24, (US$169) million for 1Q24. 

OPEX totaled US$1,744 million (-14% q/q), primarily due to savings from mature fields already divested and an environmental provision during 4Q24, as indicated in that period, plus lower transportation costs in 1Q25, on the back of fuel sales reduction.

Total Other Costs reached US$1,390 million (-4% q/q), mostly explained by the unproductive exploratory drillings recorded in 4Q24, slightly offset by higher depreciation and amortizations.

Purchases & Stock Variations amounted to US$959 million (-18% q/q). Purchases remained stable q/q, as the lower seasonality in natural gas and fertilizers was offset by increased oil prices and oil purchases, particularly to third parties, coupled with diesel imports due to higher processing levels in our refineries. Stock variations reached a positive US$69 million in 1Q25 (compared to a negative US$157 million in 4Q24), mainly explained by stock accumulation of fuels in 1Q25 (compared to stock consumption in 4Q24). Additionally, in 4Q24, we recorded lower value of inventory of oil, driven by reduced prices.

Other operating net results totaled a loss of US$323 million (-42% q/q), primarily explained by lower one-off costs related to mature fields³ (result from changes in fair value of assets held for sale, provision for obsolescence of materials and equipment, provision for severance indemnities, provision (recovery) for operating optimizations and result from sale of assets).

2	1 ADR = 1 share. Total issued capital stock amounted to 393,312,793 shares as of March-2025 (51% Argentina Government; 31% NYSE and 18% ByMA).

3	Please refer to the figures disclosed on section 2.1 of this Report.

 

Page 5/16

 

Consolidated Net Income Breakdown Unaudited Figures, in US$ million		1Q25				4Q24				1Q24				Q/Q Δ				Y/Y Δ
Operating income / (loss)			192				(530	)			666				N/A				-71.2	%
Income from equity interests in associates and joint ventures			81				133				129				-39.1	%			-37.2	%
Financial results, net			(256	)			(112	)			(259	)			128.6	%			-1.2	%
Net result before tax			17				(509	)			536				N/A				-96.8	%
Income tax			(27	)			225				121				N/A				N/A
Net result			(10	)			(284	)			657				-96.5	%			N/A
Net Income before impairment of assets			(10	)			(244	)			657				-95.9	%			N/A

Financial net results recorded a loss of US$256 million (vs. a loss of US$112 million in 4Q24), mostly driven by extraordinary gains from holding financial securities in 4Q24, and lower domestic interest income rates in 1Q25. The income tax recorded a charge of US$27 million (vs. a positive amount of US$225 million in 4Q24), mainly due to the income tax charge of our subsidiaries, while in 4Q24 we accrued a positive income tax effective rate, on the back of lower future tax payables recorded during that period.

Consequently, the net result totaled a loss of US$10 million (vs. a loss of US$284 million in 4Q24).

2. ADJ. EBITDA & CAPEX

2.1 ADJ. EBITDA RECONCILIATION

 

Reconciliation of Adjusted EBITDA Unaudited Figures, in US$ million		1Q25				4Q24				1Q24				Q/Q Δ				Y/Y Δ
Net result			(10	)			(284	)			657				-96.5	%			N/A
Financial results, net			256				112				259				128.6	%			-1.2	%
Income from equity interests in associates and joint ventures			(81	)			(133	)			(129	)			-39.1	%			-37.2	%
Income tax			27				(225	)			(121	)			N/A				N/A
Unproductive exploratory drillings			—				77				6				N/A				N/A
Depreciation & amortization			806				795				652				1.4	%			23.6	%
Impairment of PP&E and inventories write-down			—				61				—				N/A				N/A
EBITDA			998				403				1,324				147.6	%			-24.6	%
Leasing			(85	)			(85	)			(79	)			0.3	%			7.4	%
Provision for operating optimizations			—				266				—				N/A				N/A
Result from sale of assets			(14	)			(6	)			—				131.6	%			N/A
Result from changes in fair value of assets held for sale			200				260				—				-23.2	%			N/A
Provision for severance indemnities			26				—				—				N/A				N/A
Provision for obsolescence of materials and equipment			136				—				—				N/A				N/A
Miscellaneous			(16	)			—				—				N/A				N/A
Adjusted EBITDA			1,245				839				1,245				48.4	%			0.0	%

2.2 ADJ. EBITDA & CAPEX BY SEGMENT

 

By Segment		1Q25				4Q24				Q/Q Δ				1Q24				Y/Y Δ
Adj. EBITDA
Upstream			766				597				28	%			831				-8	%
Midstream & Downstream			504				371				36	%			576				-12	%
LNG & IG			(5	)			(3	)			63	%			(33	)			-85	%
New Energies			38				34				12	%			(14	)			N/A
Corp			(36	)			(113	)			-68	%			(7	)			413	%
Eliminations & Others			(24	)			(48	)			-50	%			(108	)			-78	%
Total Adj. EBITDA			1,245				839				48	%			1,245				0	%
CAPEX
Upstream			979				883				11	%			935				5	%
Midstream & Downstream			204				350				-42	%			204				0	%
LNG & IG			3				18				-83	%			0				627	%
New Energies			10				15				-30	%			5				109	%
Corp			18				54				-67	%			25				-27	%
Eliminations			—				—				N/A				—				N/A
Total CAPEX			1,214				1,320				-8	%			1,169				4	%

Note: Midstream & Dw Adjusted EBITDA excludes inventories price effect of oil products, which are included in Eliminations.

Note: According to Relevant Fact released on December 5, 2024, the Company changed the organizational structure of YPF. The main changes are: i) “Gas & Power” segment divided into two segments, “LNG & Integrated Gas” and “New Energies”; ii) “Downstream” segment renamed as “Midstream & Downstream”; iii) Midstream gas business (formerly included in “Gas & Power” segment) reallocated to “Midstream & Downstream” segment. For more information, please refer to the Relevant Fact mentioned above and Note 6 of our Financial Statements.

 

Page 6/16

 

3. ANALYSIS OF RESULTS BY SEGMENT

3.1 UPSTREAM

 

Upstream Financials Unaudited Figures, in US$ million		1Q25				4Q24				1Q24				Q/Q Δ				Y/Y Δ
Crude oil			1,646				1,591				1,559				3.5	%			5.6	%
Natural gas			394				345				354				14.0	%			11.2	%
Other			27				33				34				-16.3	%			-19.5	%
Revenues			2,067				1,969				1,947				5.0	%			6.2	%
Depreciation & amortization			(602	)			(566	)			(473	)			6.4	%			27.2	%
Lifting cost			(758	)			(828	)			(617	)			-8.5	%			22.8	%
Royalties			(262	)			(258	)			(255	)			1.7	%			2.7	%
Other costs			(564	)			(839	)			(201	)			-32.8	%			180.1	%
Operating income before impairment of assets			(119	)			(522	)			400				-77.2	%			N/A
Impairment of PP&E and inventories write-down			—				(58	)			—				N/A				N/A
Operating income / (loss)			(119	)			(580	)			400				-79.5	%			N/A
Depreciation & amortization			602				566				473				6.4	%			27.2	%
Unproductive exploratory drillings			—				77				6				N/A				N/A
Impairment of PP&E and inventories write-down			—				58				—				N/A				N/A
EBITDA			483				121				879				299.6	%			-45.0	%
Leasing			(49	)			(44	)			(49	)			10.0	%			-0.4	%
Provision for operating optimizations			—				266				—				N/A				N/A
Result from sale of assets			(14	)			(6	)			—				131.6	%			N/A
Result from changes in fair value of assets held for sale			200				260				—				-23.2	%			N/A
Provision for severance indemnities			26				—				—				N/A				N/A
Provision for obsolescence of materials and equipment			136				—				—				N/A				N/A
Miscellaneous			(16	)			—				—				N/A				N/A
Adjusted EBITDA			766				597				830				28.3	%			-7.7	%
CAPEX			979				883				935				10.9	%			4.7	%

 

Unit Cash Costs Unaudited Figures, in US$/boe		1Q25				4Q24				1Q24				Q/Q Δ				Y/Y Δ
Lifting Cost			15.3				17.3				12.9				-11.8	%			18.3	%
Royalties and other taxes			6.6				6.7				6.7				-1.9	%			-1.6	%
Other Costs			3.4				4.3				2.5				-21.4	%			36.6	%
Total Cash Costs (US$/boe)			25.3				28.3				22.1				-10.8	%			14.3	%

Revenues totaled US$2,067 million (+5% q/q), mainly driven by higher sales of natural gas (+21%), on the back of peak seasonal demand from power plants and recovery of demand from Mega, under maintenance in 4Q24. Moreover, we recorded higher crude oil price (+3%), partially offset by lower natural gas price (-6%). It is worth noting that total oil volume remained similar as shale oil growth fully offset lower conventional oil.

Lifting cost decreased to US$15.3/BOE (-12% q/q), primarily as a result of lower exposure to mature fields (certain blocks divested in 2024), plus outstanding oil productivity in La Angostura Sur block (south hub). Conventional was US$30.3/BOE (-7% q/q) and unconventional was US$5.2/BOE (-5% q/q). Excluding mature fields, total lifting cost would have been below US$9/BOE.

Zooming into the lifting cost in our shale core hub blocks (at 100% stake), it recorded US$4.6/BOE, a competitive level despite the sequential increase (+11% q/q), mainly derived from higher costs and lower production in La Amarga Chica block, expected to return to normal levels in the following months.

Royalties and other taxes averaged US$6.6/BOE (-2% q/q), mostly due to lower natural gas prices, partially offset by higher gas production and oil prices.

Other costs amounted to US$564 million (-33% q/q), primarily driven by lower costs associated with mature fields mentioned before⁴, and marginally, unproductive exploratory drillings recorded in 4Q24.

In 4Q24 the Company recognized an impairment charge of PP&E for the gas units in the Northwest Basin.

Adj. EBITDA totaled US$766 million (+28% q/q), mainly boosted by peak seasonal demand of natural gas (especially power plants), increased crude oil prices and lower losses in adjusted EBITDA from mature fields (1Q25: US$106 million vs 4Q24: US$153 million), partially offset by reduced price of natural gas.

CAPEX amounted to US$979 million (+11% q/q), mostly destined for drilling and workover activities. In 1Q25 US$914 million was allocated to unconventional assets (vs. US$861 million in 4Q24).

4	Please refer to the “Other operating net results” analysis in section 1 of this Report.

 

Page 7/16

 

Unconventional oil drilling and workover activities recorded again strong metrics: (# oil wells)

 

In terms of efficiencies within our unconventional operations, we continued achieving remarkable results, we averaged 304 meters/day of drilling speed in our core-hub blocks, and 235 stages/set-month of fracking speed. Regarding drilling speed, we began the year at a lower level than expected in some wells of Aguada del Chañar block, but we bounced back during March, reaching the fastest unconventional drilling speed in this same block: 551 meters/day drilled in 10 days for a well of almost 2,600 meters of lateral length.

 

Upstream Operating data Unaudited Figures		1Q25				4Q24				1Q24				Q/Q Δ				Y/Y Δ
Net Production Breakdown
Crude Production (Kbbld)			269.9				269.8				255.5				0.1	%			5.6	%
Conventional			121.2				129.6				140.9				-6.4	%			-14.0	%
Shale			147.3				138.1				112.3				6.7	%			31.2	%
Tight			1.4				2.1				2.3				-35.9	%			-40.6	%
NGL Production (Kbbld)			47.3				35.2				41.8				34.4	%			13.2	%
Conventional			12.8				9.0				10.6				42.2	%			20.5	%
Shale			33.8				25.4				29.9				32.8	%			12.9	%
Tight			0.7				0.8				1.2				-7.0	%			-42.6	%
Gas Production (Mm3d)			37.3				34.3				36.4				8.9	%			2.7	%
Conventional			11.4				11.2				13.1				1.9	%			-12.6	%
Shale			22.2				19.3				18.0				15.3	%			23.3	%
Tight			3.7				3.8				5.3				-2.8	%			-30.0	%
Total Production (Kboed)			552.1				520.6				526.0				6.1	%			4.9	%
Conventional			206.0				209.1				233.8				-1.5	%			-11.9	%
Shale			320.9				284.8				255.7				12.7	%			25.5	%
Tight			25.2				26.7				36.5				-5.5	%			-31.1	%
Average realization prices
Crude Oil (USD/bbl)			67.9				65.7				68.3				3.4	%			-0.6	%
Natural Gas (USD/MMBTU)			3.0				3.1				3.0				-5.6	%			-0.3	%

Crude oil production averaged 270 kbbl/d (flat q/q), once again on the back of a solid growth in shale oil (147 kbbl/d; +7% q/q), more than offsetting the contraction in conventional output (-6% q/q), including mature fields (also, certain mature fields were divested in 2024).

Natural gas production grew by +9% q/q, mainly driven by higher seasonal demand from power plants. NGL production increased by +34% q/q, returning to normal levels after the reactivation of Mega facilities.

 

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3.2 MIDSTREAM & DOWNSTREAM

 

Midstream & Downstream Financials Unaudited Figures, in US$ million		1Q25				4Q24				1Q24				Q/Q Δ				Y/Y Δ
Diesel (third parties)			1,521				1,581				1,556				-3.8	%			-2.2	%
Gasoline (third parties)			1,037				1,022				1,022				1.4	%			1.5	%
Other domestic market			641				695				580				-7.9	%			10.4	%
Export market			720				739				632				-2.6	%			13.8	%
Revenues			3,918				4,037				3,790				-2.9	%			3.4	%
Depreciation & amortization			(165	)			(191	)			(149	)			-13.7	%			10.8	%
OPEX Downstream			(535	)			(573	)			(439	)			-6.6	%			21.9	%
Fuels imports (including jet fuel—third parties)			(59	)			(28	)			(99	)			113.2	%			-40.5	%
Crude oil purchases (intersegment + third parties)			(2,131	)			(2,031	)			(1,934	)			4.9	%			10.2	%
Biofuel purchases (third parties)			(226	)			(212	)			(242	)			6.5	%			-6.6	%
Agro products purchases (third parties)			(119	)			(133	)			(70	)			-10.8	%			68.6	%
Stock variations			104				(150	)			116				N/A				-10.9	%
Other			(406	)			(540	)			(414	)			-24.9	%			-2.1	%
Operating income / (loss) before impairment of assets			382				180				560				112.3	%			-31.7	%
Impairment of PP&E and inventories write-down			—				(3	)			—				N/A				N/A
Operating income / (loss)			382				177				560				115.9	%			-31.7	%
Depreciation & amortization			165				191				149				-13.7	%			10.8	%
Impairment of assets			—				3				—				N/A				N/A
EBITDA			547				371				709				47.4	%			-22.8	%
Leasing			(36	)			(40	)			(30	)			-11.4	%			18.5	%
Adjusted EBITDA			511				331				679				54.6	%			-24.7	%
Inventories price effect of oil products			7				(41	)			102				N/A				-93.2	%
Adjusted EBITDA excl. inventories price effect of oil products			504				371				576				35.8	%			-12.5	%
CAPEX			204				350				204				-41.8	%			-0.1	%

Stock variations include price effects by US$ 8 million in 1Q25, (US$40) million for 4Q24, US$102 million for 1Q24. 

Revenues totaled US$3.9 billion (-3% q/q), mainly explained by lower seasonal diesel demand (especially in retail and agribusiness) and fertilizers, in addition to a decline in oil exports, driven by a higher vertical oil integration with our La Plata refinery, and discontinuation of jet fuel sales in our subsidiary in Chile. These effects were partially offset by better local fuel prices and growing jet fuel sales in the local market (higher demand and prices).

OPEX Downstream amounted to US$535 million (-7% q/q), primarily because of higher maintenances in 4Q24, while in 1Q25 we recorded lower fuel transportation costs, on the back of fuel sales reduction.

Fuel imports reached US$59 million (+113% q/q), mostly driven by higher diesel volumes, especially to accumulate stock and prepare for the upcoming maintenances in 2Q25. As a result, fuel imports remained at low levels, representing only 2% of total fuel sales, compared to 1% in 4Q24 and 4% in 1Q24.

Crude oil purchases (including intersegment) were US$2,131 million (+5% q/q), mostly due to higher oil prices and higher volumes purchased from third parties, in line with increased processing levels, ahead of the upcoming maintenances mentioned above. Biofuel purchases rose 6% q/q, mainly due to a 10% growth in biodiesel (+8% in volume and +2% in price), especially for restocking purposes, and 4% increase in bioethanol (+5% in volume but -1% in price), in line with gasoline production. Agro products purchases declined 11% q/q, primarily in line with lower seasonal sales of fertilizers mentioned before.

Stock variations totaled a positive US$104 million (vs. a negative US$150 million in 4Q24), mainly due to a substantial increase in inventory’s restock in 1Q25, aimed at preparing for the upcoming maintenance shutdown, compared to an inventory’s consumption in 4Q24. This was also coupled with a higher price of oil in 1Q25.

Other costs decreased 25% q/q, mainly due to an environmental provision as indicated in 4Q24, while in 1Q25 we discontinued jet fuel operations in our subsidiary in Chile.

Adj. EBITDA, excluding inventories price effect of oil products, totaled US$504 million (+36% q/q), mainly boosted by higher prices of local fuels and other refined products linked with better international prices, while in 4Q24 we recorded an environmental provision and increased costs related to higher maintenances, partially offset by lower seasonal diesel demand.

 

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