YPF Sociedad Anónima (YPF) 6-KCurrent report (foreign)

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 2024

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 ☐

3Q24 Webcast on November 8, 2024 8:30 am ET / 10:30 am BAT INVESTOR RELATIONS CENTER IR TEAM https://investors.ypf.com MARGARITA CHUN – IR MANAG 867240-001 07Nov24 03:51 Page 1 Inversoresypf@ypf.com VALENTINA LÓPEZ – IR Margarita.chun@ypf.com CHRISTIAN GONZÁLEZ – IR

Buenos Aires, November 7, 2024 – YPF (BYMA: YPFD | NYSE: YPF1), announces the 3Q24 results. 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$ and as from 1Q24, quarterly FS are also reported in both currencies (US$ and AR$). 1. MAIN HIGHLIGHTS OF 3Q24 KPI 3Q24 2Q24 Q/Q ? 3Q23 Y/Y ? 9M24 9M23 ? Revenues 5,297 4,935 7% 4,504 18% 14,542 13,117 11% Adjusted EBITDA 1,366 1,204 13% 926 47% 3,815 2,976 28% l ncia Net Result 1,485 535 178% (137) N/A 2,677 584 358% CAPEX 1,353 1,200 13% 1,451 -7% 3,722 3,930 -5% i na F FCF (173) (257) -33% (379) -54% (824) (680) 21% Net Debt 7,506 7,457 1% 6,675 12% 7,506 6,675 12% Net Leverage Ratio (x) 1.5 1.7 -8% 1.7 -10% 1.5 1.7 -10% Hydrocarbon Production (Kboe/d) 558.7 539.0 4% 519.7 8% 541.3 514.5 5% Crude Oil (Kbbl/d) 255.8 248.8 3% 236.9 8% 253.4 238.8 6% Natural Gas (Mm3/d) 40.3 38.8 4% 37.5 7% 38.5 36.8 5% am NGL (Kbbl/d) 49.5 46.1 7% 46.6 6% 45.8 44.1 4% stre Crude Oil Price (US$/bbl) 68.3 70.8 -4% 60.7 13% 69.1 63.6 9% p Natural Gas Price (US$/MBTU) 4.5 4.0 12% 4.3 4% 3.8 3.8 2% U Medanito Oil Exports (Kbbl/d) 39.2 28.6 37% 18.6 111% 30.3 8.3 266% Shale Oil Production (Kbbl/d) 125.7 113.3 11% 92.2 36% 117.1 93.1 26% Total Lifting Cost (US$/boe) 16.1 16.2 0% 15.6 3% 15.1 15.4 -2% Core-Hub Lifting Cost (US$/boe) 4.6 4.7 -2% 4.2 9% 4.2 4.1 1% Crude Processed (Kbbl/d) 298.3 299.2 0% 276.1 8% 299.5 296.0 1% am Refineries’ Utilization Rate (%) 91% 91% 0% 84% 8% 91% 90% 1% tr e Local Fuels Volume Sold (Km3) 3,449 3,431 1% 3,772 -9% 10,370 10,996 -6% n s w Local Fuels Net Price (US$/m3) 716 711 1% 584 23% 706 621 14% o D Imported Fuels (Km3) 123—N/A 253 -51% 265 918 -71% R&M Adj. EBITDA (US$/bbl) 13.3 11.5 16% 3.3 299% 14.5 11.7 23% In US$ 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. Adjusted EBITDA totaled US$1,366 million (+13% q/q), mainly driven by higher seasonal natural gas sales, coupled with tariff update at Metrogas, increased shale hydrocarbon production and local fuel prices, partially offset by higher costs in real terms and reduced conventional output, impacted by the extreme weather in Patagonia during July, affecting our conventional production. Interannually, the remarkable increase of 47% was mostly on the back of a 23% recovery of local fuel prices, 29% increase in shale output and 8% higher processing levels, partially offset by said higher costs in local currency and lower conventional output. CAPEX totaled US$1,353 million (+13% q/q but -7% y/y), over 70% concentrated in the upstream segment, primarily in shale drilling and workover activities, fully aligned with the Company’s strategy to grow in shale oil. Shale oil production averaged 126 kbbl/d (+11% q/q and +36% y/y), representing 49% of total crude oil production (2Q24: 46% and 3Q23: 39%), while Medanito oil exports continued increasing in the quarter, averaging 39 kbbl/d (+37% q/q and +111% y/y), representing 15% of our total oil production. Progress on our main projects: • Conventional Mature Fields Exit Program2 (~50 blocks), Andes project grouped 30 blocks and so far, executed 9 SPAs for 25 blocks. Recently also added 7 blocks located in the Province of Tierra del Fuego to the Andes project, amounting to a total of 37 blocks. Moreover, we obtained the Provincial approval for one of the clusters in the Province of Chubut. Regarding the blocks not included in the Andes project, we are working on different alternatives to transfer or revert them. • Construction of VMOS oil pipeline project (500 kbbl/d transportation capacity), already achieved a 50% progress in the construction of the first tranche (Vaca Muerta – Allen, 130 km), with a total capex of around US$200 million. The second tranche is composed of an oil export-dedicated pipeline (Allen – Punta Colorada, 440 km), storage tanks and monobuoys to operate VLCCs, with a total capex of around US$2.5 billion, and we are a few months ahead of initiating the construction. 1 1 ADR = 1 share. Total issued capital stock amounted to 393,312,793 shares as of Sep-2024 (51% Argentina Government; 34% NYSE and 15% ByMA). 2 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.

3Q24 YPF 2. ANALYSIS OF CONSOLIDATED RESULTS OF 3Q24 Consolidated Revenues Breakdown 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Unaudited Figures, in US$ million Diesel 1,646 1,672 1,563 -1.5% 5.3% 4,873 4,821 1.1% Gasoline 1,023 946 824 8.1% 24.0% 2,991 2,550 17.3% Natural gas as producers (third parties) 514 419 464 22.8% 10.8% 1,211 1,120 8.1% Other 1,366 1,160 1,174 17.7% 16.4% 3,317 3,275 1.3% Total Domestic Market 4,549 4,197 4,025 8.4% 13.0% 12,393 11,766 5.3% Jet fuel 125 120 127 4.5% -1.5% 399 395 0.8% Grain and flours 99 130 26 -24.0% 278.1% 255 77 231.3% Crude oil 285 226 152 25.9% 87.1% 700 210 233.0% Petchem & Other 240 262 173 -8.6% 38.2% 795 668 19.1% Total Export Market 748 738 479 1.4% 56.3% 2,149 1,351 59.1% Total Revenues 5,297 4,935 4,504 7.3% 17.6% 14,542 13,117 10.9% Net Revenues amounted to US$5,297 million (+7% q/q), mainly driven by higher seasonal sales of natural gas (as a producer and through our affiliate Metrogas – distributor – with updated tariff), as well as growing Medanito oil exports, and increasing local fuel prices, coupled with higher gasoline demand. These results were partially offset by diesel demand contraction and lower crude oil prices. Unaudited Figures, in US$ million 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Lifting cost (827) (793) (746) 4.3% 10.9% (2,238) (2,163) 3.5% Other Upstream (199) (162) (74) 22.9% 169.3% (473) (253) 87.1% Refining & Logictic cost (428) (404) (406) 5.9% 5.3% (1,169) (1,188) -1.6% Other Downstream (178) (184) (166) -3.5% 7.2% (488) (467) 4.5% G&P, Corp. & Other (330) (298) (194) 10.6% 70.3% (816) (510) 60.2% Total OPEX (1,962) (1,842) (1,586) 6.5% 23.7% (5,184) (4,580) 13.2% Depreciation & Amortization (674) (638) (864) 5.6% -22.0% (1,964) (2,493) -21.2% Royalties (294) (282) (248) 4.5% 18.7% (834) (731) 14.1% Other costs (338) (383) (281) -11.9% 20.2% (993) (790) 25.7% Total Other Costs (1,306) (1,303) (1,393) 0.2% -6.2% (3,791) (4,014) -5.6% Fuels imports (including jet fuel) (98) 0 (214) N/A -54.2% (197) (715) -72.4% Crude oil purchases to third parties (471) (469) (308) 0.4% 52.9% (1,315) (1,018) 29.2% Biofuel purchases (233) (224) (198) 4.4% 17.9% (698) (666) 4.8% Agro products purchases (208) (190) (194) 9.5% 7.2% (469) (561) -16.5% Other purchases (352) (302) (361) 16.5% -2.5% (832) (912) -8.7% Stock variations 157 (3) (127) N/A N/A 30 24 25.0% Total Purchases & Stock Variations (1,206) (1,188) (1,403) 1.5% -14.0% (3,481) (3,848) -9.5% Other operating results, net (48) (8) (3) 500.0% 1500.0% (50)—N/A Impairment of assets (21) (5) (506) 320.0% -95.8% (26) (506) -94.9% Operating Costs + Purchases + Impairment of Assets (4,543) (4,346) (4,891) 4.5% -7.1% (12,532) (12,948) -3.2% Stock variations include price effects by US$94 million in 3Q24, US$12 million for 2Q24, US$32 million for 3Q23, (US$64) million in 9M24 and (US$33) million in 9M23. OPEX totaled US$1,962 million (+7% q/q), mostly due to inflation evolution, resulting in higher costs in dollars terms, combined with non-recurrent charges related to the climate contingency in Patagonia. Total other costs amounted to US$1,306 million, essentially flat q/q, primarily driven by higher depreciation & amortization, derived from an increase in production in certain areas, and higher royalties, on the back of higher natural gas sales. This was partially compensated by lower other costs considering that 2Q24 was impacted by charges of Argerich, the first offshore ultra deep-water well in Argentina. Total Purchases and Stock Variations amounted to US$1,206 million (+2% q/q), mainly due to fuel imports for restock purposes (compared with zero imports in 2Q24), higher seasonal purchases of natural gas (Metrogas), increasing purchases of agricultural products and biofuels. Additionally, stock variation was positive in 3Q24, totaling US$157 million, compared to (-US$3 million) in 2Q24, mostly due to higher replacement cost of inventories, coupled with an increase in fuel inventory levels during the quarter. Consolidated Net Income Breakdown 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Unaudited Figures, in US$ million Operating income / (loss) 754 590 (387) 27.8% N/A 2,010 169 1089.3% Income from equity interests in associates and joint ventures 107 27 44 296.3% 143.2% 263 227 15.9% Financial results, net (163) (161) 206 1.2% N/A (583) 348 N/A Net result before tax 698 456 (137) 53.1% N/A 1,690 744 127.2% Income tax 787 79—896.2% N/A 987 (160) N/A Net result 1,485 535 (137) 177.6% N/A 2,677 584 358.4% Net Income before impairment of assets 1,499 538 192 178.4% 681.0% 2,694 913 195.1%

Net income before tax reached US$698 million (+53% q/q), as a result of an increase in operating income and equity income (mainly driven by Barragán and YPF Luz). The income tax was positive at US$787 million in 3Q24 (vs. US$79 million positive in 2Q24), mainly due to the change in the annual effective tax rate, on the back of a lower projected devaluation, which resulted in an increase in the company’s tax assets value, and thus a lower future tax payable. Accordingly, the net income amounted to US$1,485 million (+178% q/q). 3. ADJ. EBITDA & CAPEX 3.1 ADJ. EBITDA RECONCILIATION Reconciliation of Adjusted EBITDA 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Unaudited Figures, in US$ million Net result 1,485 535 (137) 177.6% N/A 2,677 584 358.4% Financial results, net 163 161 (206) 1.2% N/A 583 (348) N/A Income from equity interests in associates and joint ventures (107) (27) (44) 296.3% 143.2% (263) (227) 15.9% Income tax (787) (79)—896.2% N/A (987) 160 N/A Unproductive exploratory drillings 1 49 9 -98.0% -88.9% 56 15 273.3% Depreciation & amortization 674 638 864 5.6% -22.0% 1,964 2,493 -21.2% Impairment of assets 21 5 506 320.0% -95.8% 26 506 -94.9% EBITDA 1,450 1,282 992 13.1% 46.2% 4,056 3,183 27.4% Leasing (84) (78) (66) 7.1% 27.6% (241) (207) 16.5% Other adjustments ——N/A N/A — N/A Adjusted EBITDA 1,366 1,204 926 13.5% 47.5% 3,815 2,976 28.2% 3.2 ADJ. EBITDA & CAPEX BY SEGMENT By Segment 3Q24 2Q24 3Q23 9M24 9M23 A Upstream 784 816 732 2,430 2,146 D Downstream 448 369 183 1,386 957 I T Gas & Power 143 59 44 172 81 E B Corp (67) (61) (76) (145) (198) . Adj Eliminations & Others 58 22 43 (28) (9) Total Adj. EBITDA 1,366 1,204 926 3,815 2,976 Upstream 983 863 1,053 2,781 2,894 Downstream 298 299 303 794 765 PEX Gas & Power 45 18 39 76 137 C A Corp 26 20 55 70 134 Eliminations — ——Total CAPEX 1,353 1,200 1,451 3,722 3,930 Note: Downstream Adjusted EBITDA excludes inventories price effect of oil products, which are included in Eliminatios 3.3 ADJ. EBITDA Q/Q & Y/Y EVOLUTION

4. ANALYSIS OF RESULTS BY SEGMENT 4.1 UPSTREAM3 Upstream Financials Unaudited Figures, in US$ million 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Crude oil 1,599 1,568 1,299 2.0% 23.1% 4,726 4,068 16.2% Natural gas 616 510 550 20.6% 12.0% 1,480 1,380 7.2% Other 31 35 32 -9.9% -3.5% 100 85 17.0% Revenues 2,246 2,113 1,881 6.3% 19.4% 6,306 5,533 14.0% Depreciation & amortization (475) (449) (689) 5.7% -31.1% (1,397) (1,952) -28.4% Lifting cost (827) (793) (746) 4.3% 10.9% (2,238) (2,163) 3.5% Royalties (291) (279) (245) 4.6% 18.7% (825) (722) 14.3% Other costs (299) (230) (131) 29.8% 127.8% (730) (399) 82.9% Operating income before impairment of assets 354 362 76 -2.2% 365.8% 1,116 297 275.8% Impairment of assets (21)—(506) N/A -95.8% (21) (506) -95.8% Operating income / (loss) 333 362 (430) -8.0% N/A 1,095 (209) N/A Depreciation & amortization 475 449 689 5.7% -31.1% 1,397 1,952 -28.4% Unproductive exploratory drillings 1 49 9 -98.0% -88.9% 56 15 273.3% Impairment of PP&E and inventories write-down 21—506 N/A -95.8% 21 506 -95.8% EBITDA 830 860 767 -3.5% 8.1% 2,569 2,264 13.5% Leasing (45) (44) (37) 2.5% 22.3% (139) (118) 17.5% Other adjustments ——N/A N/A — N/A Adjusted EBITDA 784 816 736 -3.9% 6.5% 2,430 2,146 13.2% CAPEX 983 863 1,053 13.9% -6.6% 2,781 2,894 -3.9% Unit Cash Costs Unaudited Figures, in US$/boe 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Lifting Cost 16.1 16.2 15.6 -0.5% 3.1% 15.1 15.4 -2.0% Royalties and other taxes 7.0 7.2 6.5 -2.4% 6.9% 6.9 6.5 6.2% Other Costs 4.1 3.5 1.8 16.4% 128.4% 3.4 2.0 64.5% Total Cash Costs (US$/boe) 27.1 26.8 23.9 1.2% 13.4% 25.4 24.0 5.9% Revenues totaled US$2.2 billion in 3Q24 (+6% q/q), mainly driven by increased crude oil sales volume (+6%), as well as higher seasonal gas sales (+12% price and +8% volume), partially offset by lower crude oil prices (-4%), impacted by the Brent’s price contraction during the quarter. Lifting cost reached US$16.1/BOE (-0.5% q/q), primarily due to increased shale hydrocarbon production, offset by higher cost pressures in local currency, in addition to lower conventional oil production: conventional at US$31.1/BOE (+8% q/q) and unconventional at US$5.0/BOE (-12% q/q). Zooming in, lifting cost of our shale core hub blocks, on a gross basis (at 100% stake), decreased slightly to US$4.6/BOE (-2% q/q). Royalties and other taxes remained almost flat, averaging US$7.0/BOE (-2% q/q), mostly due to lower crude oil prices, offset by higher natural gas prices. Other costs totaled US$299 million (+30% q/q), primarily due to non-recurrent charges recorded in 3Q24. Adjusted EBITDA totaled US$784 million (-4% q/q), mainly driven by higher costs due to quarterly inflation outpacing the devaluation of the currency, in addition to lower crude oil prices, partially offset by higher seasonal sales of natural gas and increased crude oil sales volume. 3 As of 3Q24, certain assets related to the production of frac sand for well drilling/fracking purposes (~2% of 9M24 upstream s ales of YPF) were reallocated (upstream segment to corporate segment), restating comparative periods. This reclassification is aligned with the new management structure and aims at simplifying the business reporting and maximizing synergies.

CAPEX amounted to US$983 million (+14% q/q), driven by higher investments deployed in unconventional fields, mainly allocated to drilling and workover activities. More than 85% of the segment’s capex was deployed within the unconventional areas. Drilling and workover activities recorded strong levels, reaching 50 drilled wells, 67 completed wells and 68 tied-in wells in our operated unconventional blocks, all of them oil horizontal wells. This outstanding performance is consistent with the expected ramp-up in the shale oil production for the second half of the year. In terms of efficiencies within our unconventional operations, in 3Q24 the Company continued achieving outstanding results, averaging 314 meters per day of drilling in our core-hub blocks, and 240 stages per set per month on fracking. Regarding our exploratory strategy, we made progress in the following areas: • South of Mendoza Province, expanding the frontiers of our Core-Hub in Vaca Muerta: after completing the testing phase, during Q3, we tied-in two wells to YPF’s production facilities • Palermo Aike formation, with the potential to become the second largest unconventional resource in Argentina: we started testing the productivity of the first horizontal well in El Cerrito block. Production data gathered is under analysis • Offshore in the Northern Argentina Basin: to further explore the hydrocarbon potential of the Argentine Sea, we started processing 3D seismic data obtained from CAN-102 block, expecting results in early 2025 Upstream Operating data Unaudited Figures 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Net Production Breakdown Crude Production (Kbbld) 255.8 248.8 236.9 2.8% 8.0% 253.4 238.8 6.1% Conventional 127.7 133.1 142.0 -4.1% -10.1% 133.8 143.0 -6.4% Shale 125.7 113.3 92.2 10.9% 36.3% 117.1 93.1 25.8% Tight 2.5 2.4 2.7 3.9% -8.1% 2.4 2.7 -11.6% NGL Production (Kbbld) 49.5 46.1 46.6 7.3% 6.1% 45.8 44.1 3.9% Conventional 12.0 10.4 12.2 15.4% -1.6% 11.0 12.4 -11.1% Shale 36.5 34.5 33.1 5.8% 10.3% 33.7 30.4 10.7% Tight 1.0 1.2 1.3 -18.8% -27.2% 1.1 1.3 -12.5% Gas Production (Mm3d) 40.3 38.8 37.5 3.8% 7.3% 38.5 36.8 4.5% Conventional 12.2 12.8 13.4 -5.3% -9.2% 12.7 13.8 -8.2% Shale 23.4 21.0 18.2 11.3% 28.4% 20.8 17.3 20.2% Tight 4.7 4.9 5.9 -4.3% -20.1% 5.0 5.7 -12.4% Total Production (Kboed) 558.7 539.0 519.7 3.7% 7.5% 541.3 514.5 5.2% Conventional 216.1 224.2 238.4 -3.6% -9.3% 224.7 242.3 -7.3% Shale 309.5 280.1 240.0 10.5% 28.9% 281.9 232.5 21.2% Tight 33.2 34.6 41.2 -4.3% -19.6% 34.8 39.7 -12.3% Average realization prices Crude Oil (USD/bbl) 68.3 70.8 60.7 -3.6% 12.5% 69.1 63.6 8.6% Natural Gas (USD/MMBTU) 4.5 4.0 4.3 11.8% 4.0% 3.8 3.8 2.3% Crude oil production in 3Q24 averaged 256 kbbl/d (+3% q/q) on the back of shale oil growth (+11% q/q), more than offsetting the decrease in conventional output (-4% q/q), which remained affected by the harsh winter conditions in the south of Argentina until early August. Additionally, 9% of conventional output came from tertiary production, growing by 2% q/q and minimizing the natural decline in mature fields. Natural gas production increased by +4% q/q, mainly driven by the expansion of the GNK transportation capacity and winter peak demand. NGLs production grew by 7% q/q, following the same trend of increased shale gas production, in addition to the optimizations at the turboexpander located at the Loma La Lata block.

4.2 DOWNSTREAM Downstream Financials 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Unaudited Figures, in US$ million Diesel (third parties) 1,646 1,672 1,563 -1.5% 5.3% 4,873 4,821 1.1% Gasoline (third parties) 1,023 946 824 8.1% 24.0% 2,991 2,550 17.3% Other domestic market 753 649 814 16.0% -7.4% 1,974 2,433 -18.9% Export market 705 690 460 2.3% 53.4% 2,027 1,263 60.5% Revenues 4,127 3,957 3,661 4.3% 12.7% 11,866 11,068 7.2% Depreciation & amortization (148) (142) (141) 4.2% 5.3% (427) (422) 1.2% Refining & Logistic costs (428) (404) (406) 5.9% 5.3% (1,169) (1,188) -1.6% Fuels imports (including jet fuel—third parties) (98) 0 (214) N/A -54.2% (197) (715) -72.4% Crude oil purchases (intersegment + third parties) (2,097) (2,067) (1,630) 1.5% 28.7% (6,129) (5,169) 18.6% Biofuel purchases (third parties) (233) (224) (198) 4.4% 17.9% (698) (666) 4.8% Agro products purchases (third parties) (208) (190) (194) 9.5% 7.2% (469) (561) -16.5% Stock variations 20 (6) (265) N/A N/A 130 (153) N/A Other (661) (641) (623) 3.0% 6.1% (1,790) (1,752) 2.2% Operating income / (loss) before impairment of assets 274 284 (10) -3.4% N/A 1,116 441 153.1% Impairment of PP&E and inventories write-down ——N/A N/A — N/A Operating income / (loss) 274 284 (10) -3.4% N/A 1,116 441 153.1% Depreciation & amortization 148 142 141 4.2% 5.3% 427 422 1.2% EBITDA 422 426 131 -0.9% 223.1% 1,543 863 78.8% Leasing (29) (24) (22) 21.8% 34.2% (76) (70) 8.6% Adjusted EBITDA 393 402 109 -2.3% 260.7% 1,467 793 85.0% Inventories price effect of oil products (55) 34 (75) N/A -26.2% 81 (164) N/A Adjusted EBITDA excl. inventories price effect of oil 448 368 184 21.6% 144.0% 1,386 957 44.8% products CAPEX 298 299 303 -0.3% -1.8% 794 765 3.8% Stock variations include price effects by (US$54) million in 3Q24, US$31 million in 2Q24, (US$71) million for 3Q23, US$ 79 million for 9M24 and (US$200) million for 9M23 Revenues reached US$4.1 billion in 3Q24 (+4% q/q), mainly boosted by higher oil export volumes and local fuel prices, as well as better local demand of gasoline. These effects were partially offset by a lower seasonal demand of diesel and lower international parities. Refining and logistics costs increased by 6% q/q, primarily driven by an in increase in costs in real terms, on the back of a lower devaluation of local currency versus inflation, in addition to higher transported volumes. Fuel imports accounted US$98 million, driven by diesel volumes, especially for restocking of inventories mainly for programmed maintained stoppages. Crude oil purchases (including intersegment) grew by 1% q/q, mainly due to higher purchased oil volumes, partially offset by lower crude oil price. Biofuel purchases increased 4% q/q, as a result of higher purchased volumes of both (biodiesel +8% q/q and bioethanol +5% q/q), partially offset by lower price of biodiesel. Adjusted EBITDA, excluding inventories price effect of oil products, totaled US$448 million (+22% q/q), mainly explained by better local fuel prices and lower cost of crude oil, combined with increasing gasoline demand, partially offset by higher costs in real terms. Adjusted EBITDA of the Refining & Marketing business, in unit terms, reached US$13.3/bbl in 3Q24, compared to US$11.5/bbl reported in 2Q24 and only US$3.3/bbl in 3Q23. CAPEX totaled US$298 million, essentially flat q/q. The breakdown of total capex is as follows: 59% refining, 18% midstream oil,16% logistics and 7% commercial. In our refineries, during 3Q24 CAPEX was allocated in the following main projects: • New fuel specifications, particularly in the construction of a new diesel oil hydrotreatment unit at Luján de Cuyo refinery, which has already reached a 67% progress, and is expected to be operational in 4Q25. The main purpose of these works is to comply with the new fuel specifications established by Resolution No. 492/2023 of the Secretary of Energy. • Revamping of topping units at our refineries, which will allow us to process greater levels of shale oil. In Luján the Cuyo, our second largest refinery, we continued with the engineering and acquisition of equipment for the revamping of Topping III, that is expected to be ready by 2Q25, while in Plaza Huincul refinery we keep progressing on works for the revamping of the Topping Unit. In our midstream oil business unit, during 3Q24 we continued making progress in the main projects aimed at unlocking the evacuation capacity of the Neuquina basin:

• New evacuation to the Atlantic: regarding the Vaca Muerta South (“VMOS”) project, we achieved a 50% progress in the construction of the first tranche, consisting of a 127 km pipeline to connect Loma Campana (Neuquén Province), to Allen (Río Negro Province), which currently serves as the access point to Oldelval system. Additionally, we continued making progress on the development for the construction of the second and the most important tranche, consisting of a 440 km pipeline, fully dedicated to exports, with a commissioning capacity of 180 kbbl/d by 3Q26, and a capacity of 500 kbbl/d by 2027. This new pipeline will be able to reach more than 700 kbbl/d design capacity, if the basin requires it. • Expansion of existing system to the Atlantic: our subsidiary Oldelval is expected to gradually add around 30 kbbl/d to its current capacity (300 kbbl/d) by year end and jumping to a total of 540 kbbl/d in 1Q25. • Evacuation to the Pacific: through the reactivation of the Trans-Andean pipeline, coupled with the Vaca Muerta North pipeline, we exported 39 kbbl/d of Medanito oil to Chile in 3Q24 (+37% q/q and +111% y/y). • Connection of new areas and expansion of storage capacity related to La Amarga Chica – Puesto Hernández oil pipeline, has become operational in 3Q24 with a total evacuation capacity of around 160 kbbl/d. Additionally, we also continued the works to revamp the Puesto Hernández – Luján de Cuyo oil pipeline, to increase the transportation capacity from the Neuquina basin to Luján de Cuyo refinery, expected to be operational by 2025. Downstream Operating data Unaudited Figures 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Crude processed (Kbbld) 298.3 299.2 276.1 -0.3% 8.1% 299.5 296.0 1.2% Refinery utilization (%) 90.9% 91.2% 84.2% -26bps 678bps 91.3% 90.2% 107bps Nominal capacity at 328.1 Kbbl/d since 1Q21. Sales volume to third parties (YPF stand alone) Sales of refined products (Km3) 4,772 4,633 4,936 3.0% -3.3% 14,097 14,599 -3.4% Total domestic market 4,294 4,166 4,581 3.1% -6.3% 12,600 13,411 -6.0% of which Gasoline 1,421 1,350 1,500 5.3% -5.3% 4,282 4,445 -3.7% of which Diesel 2,029 2,082 2,272 -2.5% -10.7% 6,088 6,551 -7.1% Total export market 478 468 355 2.1% 34.5% 1,497 1,189 25.9% Sales of petrochemical products (Ktn) 168 150 151 12.2% 11.6% 471 413 13.8% Domestic market 91 75 86 21.3% 5.2% 231 240 -3.8% Export market 78 75 65 3.2% 20.2% 240 174 38.0% Sales of fertilizers, grain and flours (Ktn) 535 476 431 12.3% 24.2% 1,214 1,094 10.9% Domestic market 327 197 365 66.2% -10.4% 664 916 -27.5% Export market 208 279 66 -25.6% 217.0% 549 178 209.4% Net average prices Gasoline (USD/m3) (domestic market) 657 640 499 2.7% 31.7% 639 531 20.4% Diesel (USD/m3) (domestic market) 758 760 640 -0.2% 18.4% 755 718 5.1% Petrochemical & others refined products (USD/bbl) 70 73 73 -5.4% -5.3% 71 79 -9.2% Net Average domestic prices for gasoline and diesel are net of taxes, commissions, commercial bonuses and freights. Crude oil processed stood at 298 kbbl/d in 3Q24 remaining stable q/q, while increasing 8% y/y, mainly due to shutdowns rescheduled for the following period, while 3Q23 was impacted by 3 stoppages at Luján de Cuyo and La Plata refineries. Domestic fuel sales volumes increased by 1% q/q, on the back of a 5% recovery in gasoline demand, boosted by an increase in premium retail, partially offset by a 3% drop in diesel demand, as a result of lower seasonal diesel sales to the industrial and agricultural segments (compensated in part with higher sales in retail). Our market share remained almost flat q/q, being 55% for gasoline and 56% for diesel. Petrochemicals volumes expanded by 12% q/q, mostly due to an increased methanol demand in the local market. Fertilizers, grain and flours sales volumes grew 12% q/q, mainly driven by higher seasonal demand of grain and flours in the local market, partially offset by lower export of grain and flours. Net average fuels prices in the domestic market measured in dollar terms increased by 1% q/q and 23% y/y, mainly driven by a series of ongoing price adjustments aimed at converging to international parities and mitigating the devaluation of the currency as well as the fuel tax updates. As a result, we recorded a positive gap of 1% versus import parity in 3Q24, compared to a negative gap of 5% in 2Q24 and 28% in 3Q23.

Prices for petrochemical & other refined products declined by 5% q/q, aligned with a downward trend in international prices, partially offset by higher prices of certain products such as methanol and coke. 4.3 GAS & POWER GAS & POWER 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Unaudited Figures, in US$ million Natural gas as producers (intersegment + third parties) 583 472 516 23.5% 13.0% 1,380 1,287 7.2% Natural gas retail (third parties) 319 256 171 24.8% 87.0% 649 404 60.5% Midstream Gas Revenues (intersegment + third parties) 57 56 48 2.7% 18.9% 166 150 10.8% Other 98 79 87 24.6% 11.9% 207 216 -4.0% Revenues 1,057 862 822 22.6% 28.6% 2,401 2,056 16.8% Depreciation & amortization (28) (25) (16) 11.8% 74.9% (74) (62) 19.4% Natural gas purchases (intersegment + third parties) (741) (603) (640) 23.0% 15.8% (1,721) (1,582) 8.8% Midstream Gas purchases (intersegment) (16) (18) (15) -11.6% 9.8% (48) (48) 1.5% Operating cost & Other (148) (172) (117) -14.2% 25.9% (434) (327) 32.5% Operating income before impairment of assets 124 44 34 N/A 264.7% 124 37 235.1% Impairment of assets ——N/A N/A — N/A Operating income 124 44 34 N/A 264.7% 124 37 235.1% Depreciation & amortization 28 25 16 11.8% 74.9% 74 62 19.4% EBITDA 152 69 50 120.2% 204.0% 198 99 100.0% Leasing (9) (10) (6) -7.7% 51.2% (26) (18) 46.5% Adjusted EBITDA 143 59 44 141.8% 225.2% 172 81 111.7% CAPEX 45 18 39 159.1% 16.5% 76 137 -44.5% Revenues totaled US$1,057 million in 3Q24 (+23% q/q), mainly due to higher seasonal natural gas sales, as producer and from Metrogas, our affiliate, as distributor, coupled with new tariffs adjustments at Metrogas. Natural gas purchases grew by 23% q/q, in line with higher seasonal natural gas sales, while operating costs & other decreased by 14%, mostly because in 2Q24 the Company recognized a charge for doubtful sales receivables for US$22 million in 2Q244, mainly owed by CAMMESA. As a result of the aforementioned factors, Adjusted EBITDA totaled US$143 million, compared to US$59 million in 2Q24. CAPEX totaled US$45 million (+159% q/q but quite stable y/y) and was focused on the following projects: • Revamping of the natural gas treatment plant at Loma Negra, aiming to increase the current processing capacity, expected to be fully operational before year end • Argentine LNG project: a strategic pillar of the Company to monetize shale gas from Vaca Muerta. We already defined the location, in the province of Río Negro, and expect FID to be in place by 2H25 • South Hub gathering project: mainly to expand gas processing capacity at Sierra Barrosa treatment plants • North Hub gathering project: construction of a gas pipeline connecting Narambuena and Bajo del Toro blocks with El Portón Industrial Complex 4 According to Resolution N° 58/24 of the Secretary of Energy, released on May 8, 2024, the Company recognized a charge for dou btful sales receivables within operating costs of US$22 million in 2Q24 and US$29 million in 1Q24, mainly owed by CAMMESA.

5. LIQUIDITY AND SOURCES OF CAPITAL 5.1 CASH FLOW SUMMARY Summary Consolidated Cash Flow 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Unaudited Figures, in US$ million Cash BoP 1,041 1,309 1,167 -20.5% -10.8% 1,123 773 45.3% Net cash flow from operating activities 1,695 1,422 1,399 19.2% 21.2% 4,206 4,205 0.0% Net cash flow from investing activities (1,439) (1,464) (1,321) -1.7% 8.9% (4,111) (3,769) 9.1% Net cash flow from financing activities (398) (206) 158 93.2% N/A (292) 389 N/A FX adjustments & other (22) (20) (107) 10.0% -79.4% (49) (302) -83.8% Cash EoP 877 1,041 1,296 -15.8% -32.3% 877 1,296 -32.3% Investment in financial assets 318 353 182 -9.9% 74.7% 318 182 74.7% Cash + short-term investments EoP 1,195 1,394 1,478 -14.3% -19.1% 1,195 1,478 -19.1% FCF (173) (257) (379) -32.7% -54.4% (824) (680) 21.2% FCF = Cash flow from Operations less capex (Investing activities), M&A (Investing activities), and interest and leasing payments (Financing activities). Net cash flow from operations, coupled with investing activities, totaled a positive US$256 million in 3Q24. Although adjusted EBITDA was similar to capex in 3Q24, higher activity levels in the upstream business increased temporarily accounts payable. Net cash flow from financing activities amounted to a negative US$398 million in 3Q24, mostly driven by the higher debt service payment. As a result, the free cash flow for the period was negative at U$173 million, as our investing activities and our interest payments were not fully compensated by the cash flow from operations. In terms of liquidity, our cash and short-term investments declined to US$1,195 million by the end of September 2024, reducing 14% vs. 2Q24. 5.2 NET DEBT Net debt breakdown Unaudited Figures, in US$ million 3Q24 2Q24 3Q23 Q/Q ? Short-term debt 1,832 1,651 1,546 11.0% Long-term debt 6,869 7,200 6,607 -4.6% Total debt 8,701 8,851 8,153 -1.7% Avg. Interest rate for AR$-debt 37.9% 43.8% 109.2% Avg. Interest rate for US$-debt 6.5% 6.2% 6.2% % of debt in AR$ 0.7% 4.2% 2.5% Cash + short term investments 1,195 1,394 1,478 -14.3% % of liquidity dollarized 81.8% 116.8% 98.0% Net debt 7,506 7,457 6,675 0.7% Average interest rates for AR$ and US$ debt refer to YPF on a stand-alone basis. As of September 30, 2024, YPF’s consolidated net debt totaled US$7.5 billion (similar to 2Q24), while the adjusted EBITDA grew significantly in 9M24 (+28% vs. 9M23), reducing net leverage ratio from 1.7x to 1.5x. In terms of financing, during 3Q24, we issued a 7-year unsecured international bond for US$540 million with a yield of 8.75%, amortizing 20% in 2029, 20% in 2030 and 60% in 2031, in order to be allocated as follows: • US$500 million: we repurchased US$334 million of the 2025 Notes and US$166 million of the 2027 Notes • US$40 million: we exchanged the 2025 Notes for the new Notes In the local capital market, we issued a 2-year dollar-linked bond for US$185 million at a 0% yield. We also obtained promissory notes for US$100 million at a 0% yield, with maturities up to 18 months and a syndicated loan from 3 local relationship banks for US$ 300 million, with a total average life of 2.2 years.

After Q3, we issued two 4-year new dollar-denominated bonds for a total of US$150 million: US$125 million MEP and US$25 million CCL, at a 6.5% and 7.0% yield, respectively. Regarding our maturity profile, the Company faces debt maturities for the remaining 3 months of 2024 for US$107 million, mainly concentrated in international bonds’ amortizations and short-term trade facilities. The following chart shows our consolidated principal debt maturity profile as of September 30, 2024:

6. TABLES 6.1 CONSOLIDATED BALANCE SHEET Consolidated Balance Sheet Unaudited Figures 30-Sep-24 31-Dec-23 Non-current Assets Intangible assets 407 367 Properties, plant and equipment 18,102 17,712 Assets for leasing 551 631 Investments in companies and joint ventures 1,858 1,676 Deferred tax assets, net 67 18 Other receivables 290 158 Trade receivables 31 31 Investment in financial assets 0 8 Total Non-current Assets 21,306 20,601 Current Assets Assets held for disposal 2,072 0 Inventories 1,713 1,683 Contract assets 38 10 Other receivables 498 381 Trade receivables 1,936 973 Investment in financial assets 318 264 Cash and cash equivalents 877 1,123 Total Current Assets 7,452 4,434 Total Assets 28,758 25,035 Total Shareholders´ Equity 12,135 9,051 Non-current Liabilities Provisions 756 2,660 Deferred tax liabilities, net 92 1,242 Contract liabilities 31 34 Income tax payable 3 4 Other taxes payable 0 0 Salaries and social security 8 0 Liabilities from leasing 290 325 Loans 6,869 6,682 Other liabilities 71 112 Accounts payable 6 5 Total non-current Liabilities 8,126 11,064 Current Liabilities Liabilities directly associated with assets held for sale 2,204 0 Provisions 186 181 Contract liabilities 77 69 Income tax payable 93 31 Other taxes payable 260 139 Salaries and social security 389 210 Liabilities from leasing 296 341 Loans 1,832 1,508 Other liabilities 181 122 Accounts payable 2,979 2,319 Total Current Liabilities 8,497 4,920 Total Liabilities 16,623 15,984 Total Liabilities and Shareholders’ Equity 28,758 25,035 Note: Information reported in accordance with International Financial Reporting Standards (IFRS).

6.2 CONSOLIDATED INCOME STATEMENT Income Statement 3Q24 2Q24 3Q23 Q/Q ? Y/Y ? 9M24 9M23 Y/Y ? Unaudited Figures, in US$ million Revenues 5,297 4,935 4,504 7.3% 17.6% 14,542 13,117 10.9% Costs (3,678) (3,457) (3,689) 6.4% -0.3% (10,154) (10,497) -3.3% Gross profit 1,619 1,478 815 9.5% 98.7% 4,388 2,620 67.5% Selling expenses (552) (577) (483) -4.3% 14.3% (1,596) (1,385) 15.2% Administrative expenses (224) (210) (194) 6.7% 15.5% (575) (518) 11.0% Exploration expenses (20) (88) (16) -77.3% 25.0% (131) (42) 211.9% Impairment of property, plant and equipment and intangible assets (21) (5) (506) 320.0% -95.8% (26) (506) -94.9% Other operating results, net (48) (8) (3) 500.0% 1500.0% (50)—N/A Operating income 754 590 (387) 27.8% N/A 2,010 169 1089.3% Income of interests in companies and joint ventures 107 27 44 296.3% 143.2% 263 227 15.9% Financial Income 19 (97) 1,042 N/A -98.2% 87 2,435 -96.4% Financial Cost (267) (194) (930) 37.6% -71.3% (911) (2,482) -63.3% Other financial results 85 130 94 -34.6% -9.6% 241 395 -39.0% Financial results, net (163) (161) 206 1.2% N/A (583) 348 N/A Net profit before income tax 698 456 (137) 53.1% N/A 1,690 744 127.2% Income tax 787 79—896.2% N/A 987 (160) N/A Net profit for the period 1,485 535 (137) 177.6% N/A 2,677 584 358.4% Net profit for shareholders of the parent company 1,470 519 (128) 183.2% N/A 2,638 548 381.4% Net profits for non-controlling interest 15 16 (9) -6.3% N/A 39 36 8.3% Earnings per share attributable to shareholders of the parent 3.75 1.32 (0.33) 184.1% N/A 6.73 1.40 380.7% company (basic and diluted) Note: Information reported in accordance with International Financial Reporting Standards (IFRS). 7. 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 roughly 35% and 30% of the country’s crude oil and natural gas, respectively; (ii) in the downstream, we operate 3 refineries representing approximately 50% of Argentina’s refining capacity and lead the local diesel and gasoline sales with a market share of more than 55%; and (iii) in gas and power, Metrogas, our subsidiary, distributes around 25% of the country’s natural gas, while YPF Luz, our affiliate, is the third largest power gen eration company in Argentina. The Government is the controlling shareholder with a 51% stake, and YPF is listed in the NYSE and ByMA. 8. 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. Ce rtain 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 y our sole risk. Any opinions presented herein are based on general information gathered at the time of writing and are subject to change without notice. I n 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 con nection 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 achieve ments is a forward-looking statement. Although the assumptions and estimates on which forward-looking statements are based are believed by our management to be reasonable and based on the best currently available information, such forward-looking statements are based on assumptions that are inherently subject to significant uncertainties and contingencies, many of which are beyond our control. Forward-looking statements speak only as of the date on which they were made, and we undertake no obligation to release publicly any updates or revisions to any forward-looking statements contained herein because of new information, future events or other factors. In light of these limitations, undue reliance should not be placed on forward-looking statements contained in this document. Further information concerning risks and uncertainties associated with these forward-looking statements and YPF’s business can be found in YPF’s public disclosures filed on EDGAR (www.sec.gov) or at the web page of the Argentine National Securities and Exchange Commission (www.argentina.gob.ar/cnv). You should not take any statement regarding past trends or activities as a representation that the trends or activities will continue in the future. Accordingly, you should not put undue reliance on these statements. This document is not intended to constitute and should not be construed as investment advice. The information contained herein has been prepared to assist interested parties in making their own evaluations of YPF.

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.