YPF Sociedad Anónima ($YPF): Shale Growth, LNG and Argentina Risk

01 Three scenarios: more shale, but not the same risk profile as a global major

Constructive scenario — operating gains survive a less favorable price environment

YPF’s constructive scenario is a combination of rising shale production, efficient refining and additional access to export markets. The company reported 212.7 thousand barrels per day of shale oil in the second quarter of 2026, compared with 145.1 thousand a year earlier. That production represented about 80% of total crude output. At the same time, refinery throughput reached 350.8 thousand barrels per day. These are operating results, not estimates of an undeveloped resource.[3]

The economic test is whether those gains continue to translate into cash when commodity prices or refining margins become less accommodating. Second-quarter free cash flow was $824 million under YPF’s definition, after capital expenditure, acquisition spending, interest and lease payments. Net debt declined to $7.654 billion. A stronger operating mix and a less stretched financial position can reinforce each other, provided the next round of investment earns a sufficient return.[3]

In this scenario, the transition out of mature conventional fields frees operating capacity and capital for Vaca Muerta. New infrastructure expands the destinations available for the resulting barrels. LNG development progresses through defined investment decisions, financing commitments and construction milestones. The favorable outcome is not simply a larger company: it is a company able to fund expansion, service obligations and retain financial flexibility through a commodity cycle. That is an editorial scenario rather than a forecast.

Middle scenario — strong assets, uneven quarterly cash generation

A middle outcome allows continued shale growth without assuming every project delivers on its first timetable. YPF’s August presentation targeted approximately 215 thousand barrels per day of average shale oil production in 2026 and an exit rate of approximately 250 thousand in December. These are different measures: a year-end rate can be materially higher than the full-year average. The same presentation raised the capital expenditure outlook to $5.8–$6.2 billion.[4]

Production can improve while free cash flow fluctuates with inventories, collections, taxes and project spending. A seasonally strong gas quarter is not a permanent increase in gas demand, and a higher inventory valuation is not the same thing as selling more product. In a middle scenario, export projects extend YPF’s opportunity but their capital demands arrive before their full revenue contribution. Country risk continues to affect funding costs even if company execution improves.

Adverse scenario — the price, policy and funding shocks reinforce one another

The adverse case is a combination of weaker commodity realizations, pressure on domestic prices and more expensive capital. It can occur without a geological disappointment. Lower cash generation makes a large investment program harder to finance; delayed infrastructure limits market access; political intervention can weaken the relationship between international prices and local revenues. YPF identifies each of these broad exposures in its annual risk discussion. In its 2025 Form 20-F, YPF also reported that it did not maintain insurance coverage for cybersecurity incidents.[1]

State control creates a further distinction from a widely held private producer. The Argentine Republic’s controlling stake enables it to determine matters requiring a shareholder majority, including the election of most directors. Corporate priorities can therefore diverge from the preferences of minority holders. The nationalization litigation has a separate procedural history and does not turn every sovereign liability into an obligation of YPF.[1][9]

No scenario supplies a share-price target or an instruction to trade. The useful distinction is between evidence that changes the company’s operating economics and headlines that change investors’ willingness to pay for those economics. The two can move together, but they do not have to. A successful production program can coexist with a wider country-risk discount, just as a favorable macro narrative can precede delivery of the underlying projects.

02 The business: an integrated Argentine energy system

YPF Sociedad Anónima is incorporated in the Republic of Argentina and has its principal executive offices at Macacha Güemes 515 in the Autonomous City of Buenos Aires. Its annual SEC reporting is on Form 20-F, with material and interim disclosures furnished on Form 6-K. The SEC identifies the issuer with CIK 0000904851. The company is a foreign private issuer reporting under IFRS, not a domestic U.S. company filing a conventional sequence of Forms 10-K and 10-Q.[1][2]

The business combines upstream oil and gas, midstream and downstream activities, LNG and integrated gas, and new energies. Upstream explores for and produces hydrocarbons. Midstream and downstream refine, transport and market oil products, operate petrochemical activities and serve agribusiness customers. LNG and integrated gas include natural gas commercialization and the development of liquefaction capacity. New energies include power generation interests, gas distribution and technology activities.[1]

Integration helps explain why total company results are more complicated than a simple oil-price exposure. YPF produces crude, but also purchases crude from third parties to supply its refining system. It sells fuels to domestic customers and exports a range of products. A higher crude price can support upstream realizations while increasing the cost of downstream feedstock. Refining margins, local pricing and inventory movements determine how those effects combine.[1][3]

The second-quarter release reported $5.475 billion of domestic-market revenue and $1.099 billion of export-market revenue, together totaling $6.574 billion. The domestic market therefore remained the larger source of sales even while the strategy emphasized export infrastructure. Export potential is important, but the current company remains deeply connected to Argentine consumption, pricing and economic conditions.[3]

Segment revenue is not interchangeable with consolidated revenue. Sales between business units can appear in segment disclosures and are eliminated on consolidation. Similarly, a joint venture can contribute income from equity interests without its entire sales base being consolidated into YPF revenue. Understanding those boundaries prevents an apparent increase in business size from being mistaken for an equivalent increase in cash available to the parent.

The strategic direction is the 4×4 plan: prioritize Vaca Muerta, actively manage the portfolio, improve upstream and downstream efficiency, and develop Argentina LNG. The annual report describes reinvestment, partners and debt financing as elements of that plan. Those choices place project selection and execution at the center of the equity story. Scale is useful only when it produces returns after operating costs, taxes, infrastructure and financing.[1]

03 The instrument: one ADS now represents ten Class D shares

YPF’s U.S.-listed instrument is an American Depositary Share traded on the New York Stock Exchange under YPF. The locally traded Class D share is listed on Bolsas y Mercados Argentinos under YPFD. A U.S. quotation is a dollar price for the ADS, whereas the local quotation is a peso price for the ordinary share. The depositary is The Bank of New York Mellon.[1][5]

On August 4, 2026, a ten-for-one ordinary-share split took effect. Each ARS10-par ordinary share became ten ARS1-par shares. Total issued ordinary shares changed from 393,312,793 to 3,933,127,930, while nominal share capital remained ARS3,933,127,930. Each post-split ordinary share carries one vote; the ADS represents ten underlying Class D shares rather than a separate class of corporate voting stock. In parallel, the depositary ratio changed from one Class D share per ADS to ten Class D shares per ADS. The company stated that economic ownership percentages and voting rights were unchanged by the split.[5][6]

The distinction matters for every per-share comparison. The U.S. ADS did not become ten separately quoted ADSs merely because the underlying ordinary shares were split. Multiplying an ADS price by the full post-split ordinary-share count without dividing by ten would overstate an ADS-equivalent valuation by a factor of ten. Conversely, using a peso ordinary-share price against an old pre-split denominator would understate the ordinary-share valuation.

The June interim statements, issued after the split became effective, retrospectively adjusted earnings per ordinary share under IAS 33. They report second-quarter basic and diluted earnings per ordinary share of $0.31 and first-half earnings per ordinary share of $0.41. The earlier results-release table used the pre-split share basis. The changed unit, rather than a changed profit pool, explains the difference between the presentations.[2][3]

An ADS holder’s rights are exercised through the depositary arrangements rather than by treating the ADS as a U.S.-incorporated common share. Voting procedures, conversion between instruments, distributions and potential fees can differ from direct ownership of an Argentine ordinary share. The annual report also describes risks from different trading hours, currencies and the time required to surrender ADSs and obtain underlying shares.[1]

The 2025 annual report describes a further voting feature: if the depositary receives no instructions for the underlying Class D shares, it votes them according to the board’s recommendations, provided YPF supplies an Argentine counsel opinion that the recommended action is not illegal or contrary to the bylaws or board regulations.[1]

The fee table in the 2025 annual report listed up to $5 per 100 ADSs, or a portion of 100 ADSs, for issuance or cancellation and up to $0.50 per ADS per calendar year for depositary services. The table separately listed expenses, currency-conversion charges and taxes.[1]

Finviz recorded an October 13, 2026 closing reference of $51.79 for the NYSE-listed instrument. That is a dated ADS reference, not a current quote guaranteed at the time of reading. The Argentine Republic remains the disclosed controlling shareholder; the U.S. instrument’s market quotation and domestic voting control describe different aspects of YPF’s capital structure.[16][1]

04 Vaca Muerta: production growth and the denominator behind the story

Second-quarter total hydrocarbon production was 544.4 thousand barrels of oil equivalent per day. Within that total, crude production was 265.5 thousand barrels per day, natural gas was 37.3 million cubic meters per day and natural gas liquids were 44.6 thousand barrels per day. These units describe different products; gas cubic meters cannot be added directly to oil barrels without an explicit conversion.[3]

Shale oil increased to 212.7 thousand barrels per day from 205.4 thousand in the first quarter and 145.1 thousand in the prior-year second quarter. Total crude, however, declined sequentially from 271.0 thousand barrels per day, as conventional divestments offset part of the shale increase. A falling total and a rising growth segment are therefore compatible. The company’s portfolio is changing as well as growing.[3]

The operating disclosure includes the additional 4.9% production interest in Bandurria Sur obtained through the May transaction, while noting that this portion is not consolidated in YPF’s balance sheet. That qualification is important when comparing physical production with the accounting perimeter. Operational participation and financial consolidation are related concepts, but they are not identical.[3]

Natural gas production increased from 32.8 million cubic meters per day in the first quarter to 37.3 million in the second, but remained below the 39.7 million recorded a year earlier. YPF attributed the sequential increase primarily to higher shale gas output, led by La Calera, Rincón del Mangrullo, Aguada Pichana Oeste and Aguada de la Arena. Winter demand and portfolio changes both shape the comparison.[3]

The August presentation retained approximately 215 thousand barrels per day of average shale oil for the full year and approximately 250 thousand at the December exit rate. A production average measures the entire year’s contribution. An exit rate describes a point near the end of that year. Reaching an exit target does not retrospectively give all twelve months the same rate, and it does not by itself establish next year’s average.[4]

The most informative operating progression is a sequence: drilling, completion, connection to facilities, sustained output and a market for that output. A drilled well still requires completion and tie-in before it becomes a producing asset. A producing asset requires transport capacity and an economically useful destination. The chain is why upstream productivity and midstream execution belong in the same assessment, rather than in separate optimistic narratives.

05 Costs and well activity: lifting cost is not a full-cycle breakeven

YPF’s second-quarter underlying total lifting cost was $8.4 per barrel of oil equivalent, compared with $12.3 a year earlier. Its shale oil hub underlying lifting cost was $4.0 per barrel of oil equivalent. The company excludes specific well-servicing costs from these underlying figures; including those costs gives $8.7 and $4.5, respectively. The exclusion is small relative to the overall story but material to the precise definition.[3]

The shale oil hub cost is a designated operating measure, not the cost of all YPF production. It also cannot be described as the full-cycle breakeven price of a new barrel. Drilling and completion investment, royalties, taxes, transport, financing and corporate expenses sit outside a simple lifting-cost comparison. A favorable operating cost supports competitiveness without removing the need to recover the capital spent to develop the asset.

The same release reported total upstream cash costs of $19.7 per barrel of oil equivalent in the second quarter, including royalties and other taxes and other costs in its unit-cost presentation. This broader operating measure rose from $17.3 in the first quarter even as underlying lifting cost declined. Higher realized prices increased price-linked royalties and revenue-related charges. Better production economics do not require every cost category to decline simultaneously.[3]

Well activity expanded: 56 gross unconventional horizontal oil wells were drilled, 61 completed and 65 tied in during the second quarter, versus 46, 47 and 43 in the first. The release supplies different average working interests for the groups and identifies non-operated wells within completed and tied-in totals. Gross well counts therefore measure activity across participating assets, not a count of wholly owned YPF wells.[3]

Productivity data offer another useful but bounded signal. YPF reported first-half drilling speed of 354 meters per day in its shale oil hub and unconventional fracturing activity of 11.4 stages per set per day. Faster work can improve utilization of people and equipment, but it is not automatically a proportional reduction in total development cost. Well design, location, service prices and production performance still determine the economic result.[3]

For the next operating comparison, the meaningful question is whether more activity produces sustained output without an excessive increase in capital per delivered barrel. A short-lived activity record is less informative than repeated delivery across pads and blocks. Maintenance requirements, service availability and reliable evacuation capacity remain practical constraints even when the underlying formation and drilling program perform well.

06 Reserves: a dated economic estimate, not all the gas in the basin

YPF’s August investor presentation showed 2025 total proved hydrocarbon reserves of 1,284 million barrels of oil equivalent. It showed Vaca Muerta proved reserves of 1,128 million barrels of oil equivalent, or approximately 88% of the total. The presentation’s proved-reserve discussion is anchored to the year-end reserve base; it is not a measurement of reserves newly established in the second quarter of 2026.[4] The year-end SEC reserve supplement split the 1,284 million boe equally between developed and undeveloped reserves, at 642 million boe each, with undeveloped reserves representing 50% of the total. Approximately 81 million boe were in blocks whose divestment agreements had not yet been finalized and remained under negotiation at December 31, 2025.[1]

Proved reserves differ from geological resources, acreage and a prospective inventory of wells. The presentation itself warns that resource descriptions may include quantities that do not meet SEC definitions of proved, probable or possible reserves. Resources can be strategically important while requiring substantial investment, future infrastructure and favorable economics before becoming recoverable commercial volumes.[4][1]

Reserve growth can come from extensions, discoveries, improved recovery and revisions, while production reduces the remaining volume. Purchases and sales also change the denominator. A portfolio divestment may reduce booked reserves even if the retained portfolio becomes more competitive. Reserve replacement is therefore more useful when interpreted together with the nature and cost of the additions, not simply as a percentage above a threshold.

Undeveloped reserves represent a particular execution obligation. They require investment to become producing reserves, and their value depends on carrying out a development plan within the applicable economic and technical assumptions. A large reserve position is not an inventory of cash in the bank. The annual report emphasizes estimation uncertainty, the effect of prices and the risk that reserves and actual production differ from estimates.[1]

A reserve-life ratio can illustrate the relationship between a reserve base and a historical production rate, but it is not a date on which the company is expected to run out of hydrocarbons. Production changes, new development and reserve revisions alter that relationship. The long-term question is whether YPF can repeatedly replace produced volumes with economically attractive additions while avoiding an investment burden that outruns cash generation.

The strategic importance of Vaca Muerta consequently rests on more than size. Accessible acreage, working interests, well performance, transport and markets have to combine into an economic system. The basin-wide opportunity can exceed the portion attributable to YPF. Partner ownership and project-level commitments determine how much of the industry’s eventual output and cash flow belongs to YPF’s shareholders.

07 Refining and domestic fuels: a strong quarter, with policy sensitivity

YPF processed 350.8 thousand barrels per day of crude in the second quarter, compared with 301.4 thousand a year earlier. Reported utilization was approximately 104%, measured against the company’s nominal refinery-capacity denominator. A utilization rate above 100% reflects that reference basis and operating throughput; it is not a statement that the facilities have unlimited sustainable capacity.[3][4]

Domestic gasoline and diesel volume in the headline operating table was 3.869 million cubic meters, including the specified Refinor contribution. Net local fuel price averaged $920 per cubic meter, against an import-parity reference of $1,015. Prices were stated net of the applicable taxes, commissions, commercial bonuses and freight in the detailed operating discussion.[3]

The company explained that international-price increases were largely reflected in local pump prices during the quarter. This provided an important source of earnings strength. It also makes local price formation a central monitoring issue: a large domestic sales base means YPF remains exposed to consumers’ purchasing power, inflation, exchange-rate movements and political pressure even as upstream exports expand.[3][1]

Refining and marketing adjusted EBITDA per processed barrel was $23.2, compared with $14.9 in the first quarter. The broader midstream and downstream segment presentation separately reports adjusted EBITDA excluding inventory price effects of oil products. These are measures with different scopes. A unit margin for refining and marketing cannot simply be multiplied across every activity in the segment.[3]

The consolidated results also contained a positive inventory price effect of $219 million in the second quarter. YPF’s segment tables allocate inventory effects differently, and the midstream and downstream comparison excludes an identified inventory-price effect. The result is that consolidated improvement and a specific segment inventory movement can have different signs. The complete reconciliation is more informative than choosing whichever isolated line supports a preferred interpretation.[3]

Avoiding gasoline and diesel imports supported performance, but the release still identifies jet-fuel imports. The narrower statement is that there were no diesel or gasoline imports in the quarter, not that every imported fuel category was zero. Maintenance timing also matters: the prior-year second quarter included a La Plata shutdown, while April 2026 included programmed maintenance at Luján de Cuyo.[3]

The refinery system requires continuing integrity and specification investment. The release reported the Luján de Cuyo diesel hydrotreating unit operational from July, and May investment decisions for new hydrotreating units at La Plata and Plaza Huincul. Those decisions belong to refinery compliance and upgrading, separate from the still-pending investment decision for the large Eni–YPF–XRG LNG project.[3]

08 The quarter’s earnings: separate IFRS profit from adjusted EBITDA

The audited 2025 annual statements provide a useful baseline: $18.448 billion of revenue and $1.740 billion of operating profit, but a $799 million net loss after $1.709 billion of income tax expense. In 2024, revenue was $19.293 billion and net profit $2.393 billion, with an income tax benefit of $1.373 billion. The change illustrates how operating profit and bottom-line profit can diverge substantially when tax and financial results change. Of the 2025 income-tax charge, $1.049 billion related to the ARCA tax-loss-carryforward regularization plan, which YPF decided to enter on November 18, 2025 for the 2024 tax period. The regime provided for 120 monthly installments; the recognized expense is not the amount of cash already paid.[1]

For the quarter ended June 30, 2026, YPF reported revenue of $6.574 billion, IFRS operating profit of $1.813 billion and net profit of $1.205 billion. Net profit attributable to parent-company shareholders was $1.201 billion, with the remaining $4 million attributable to non-controlling interests. The ownership allocation matters when moving from group profit to per-share earnings.[2]

For the first six months, revenue was $11.520 billion, operating profit $2.691 billion and net profit $1.614 billion. Parent-attributable profit was $1.605 billion. These first-half totals include both quarters; adding the second-quarter result to them would double-count that quarter. The comparison also shows why a single exceptional quarter should not be treated as a permanent quarterly run rate.[2]

Adjusted EBITDA of $2.804 billion was a company-defined non-IFRS measure. The release reconciles net profit to EBITDA and then adjusts for lease effects and specified items, including mature-field provisions, fair-value changes in assets held for sale and liabilities for agreements. Adjusted EBITDA can illuminate operating trends, but it is neither IFRS operating profit nor cash available after investment and debt service.[3]

The quarter benefited from higher commodity prices, shale production, refining throughput and seasonal natural gas sales. YPF also identified inventory valuation effects and one-off mature-field items. That mixture means improvement was not generated by a single permanently repeatable factor. Some drivers reflect operational gains; others reflect the market environment or timing within the financial statements.[3]

The August presentation increased the 2026 adjusted EBITDA outlook to approximately $8 billion from the prior approximately $6 billion framework. It accompanied that outlook with a changed pricing environment, a full-year Brent assumption of approximately $82 per barrel and approximately $75 for the second half. The forecast is management’s, and the stated assumptions are part of its meaning.[4]

A change in guidance is not the same thing as realized annual earnings. The remaining quarters still need to deliver the operating, pricing and cost conditions underlying the forecast. Net leverage, measured as net debt divided by trailing adjusted EBITDA, can fall because debt declines, the earnings base rises, or both. A strong commodity period can make leverage look more comfortable just before the earnings cycle weakens.

09 Cash and debt: $2.474 billion of liquidity is not all bank cash

At June 30, 2026, cash and cash equivalents were $1.318 billion. Current investments in financial assets were another $1.156 billion. YPF’s results materials combined them as cash plus short-term investments of $2.474 billion. The separate categories matter: the larger figure is a liquidity presentation, not a balance-sheet line containing only cash and cash equivalents.[2][3] Within cash and cash equivalents, Note 17 reported $322 million of cash and bank balances, $236 million of short-term investments and $760 million of financial assets at fair value through profit or loss; cash and bank balances included collateral. Note 37 also identifies Argentine Republic 2029 and 2030 bonds, National Treasury Bills and BCRA BOPREAL bonds within financial investments.[2]

The company reported current loans of $1.607 billion and non-current loans of $8.521 billion, totaling $10.128 billion. Subtracting $2.474 billion of cash plus short-term investments gives its $7.654 billion net debt measure. Lease liabilities were reported separately at $304 million current and $410 million non-current. They are obligations even though they are not included by simply relabeling the loan total as every liability.[2][3]

The results release reported approximately 99.5% of debt in U.S. dollars and 67.6% of liquidity dollarized. The mismatch is a reminder that a dollar presentation does not mean every asset, liability and cash flow is economically dollar-matched. Access to hard currency, local instruments and currency-linked obligations can influence the practical usefulness of a stated liquidity balance.[3]

First-half operating cash flow was $4.237 billion. Cash acquisitions of property, plant and equipment and intangible assets were $2.217 billion. Investment in financial assets, contributions and acquisitions of interests, disposal proceeds and financing payments occupy separate lines. The statement permits a more precise view of cash deployment than subtracting one headline capital expenditure figure from adjusted EBITDA.[2]

YPF’s company-defined free cash flow was $824 million for the second quarter and $1.695 billion for the first half. It subtracts capital expenditure, M&A, interest and leasing payments from operating cash flow. The definition is broader than a common operating-cash-flow-minus-capex shortcut. Two measures labeled free cash flow can therefore differ even when both use correctly reported inputs.[3]

Debt maturity management continued after June. September tender results accepted $318.514 million principal of the 2027 securities and $247.609 million of the 2029 securities on their original-principal basis. The latter required the stated amortization factor of 0.85714. The announcement expected settlement on September 18; acceptance, outstanding principal and settlement cash are distinct measures.[14]

October’s Class XXVII repurchase disclosure reported an additional $14.853 million of par value acquired between October 5 and October 7, for ARS22.599 billion, at an average equivalent price of 99.98% of nominal value. These were debt-security repurchases held in portfolio, not purchases of YPF ordinary shares and not an operating profit figure.[15]

The separate October 5 notice covered Class XXVII purchases made from September 28 through October 2: US$4,374,760 of par value for ARS6,660,251,170.56, at an average equivalent price of 99.91% of nominal value. Those notes were also to be held in portfolio.[23]

10 Capital expenditure and portfolio changes: timing makes the bridge difficult

Second-quarter capital expenditure was $1.340 billion and first-half capital expenditure $2.321 billion in YPF’s headline investment presentation. The company revised the investment definition during the second quarter, excluding acquisitions due to M&A from that measure. The change did not alter the accounting standards applied to the financial statements, but it affects how the operational investment figure is interpreted.[3]

The quarter’s upstream investment was $1.066 billion, while midstream and downstream investment was $213 million. Seventy-seven percent of consolidated headline capex went to unconventional operations. YPF identified the accrual of signing bonuses for five Argentina LNG unconventional blocks among the reasons for the sequential increase. An accrual-based investment measure and a cash acquisition line need not have identical timing.[3]

The updated annual capex range was $5.8–$6.2 billion, with approximately 70% directed to shale. The August presentation also targeted approximately $2 billion of annual free cash flow and approximately 1.0 times year-end net leverage. The free-cash-flow outlook included collections from M&A transactions in progress. That dependency means disposal completion and collection timing are part of the outlook, not a separate optional upside.[4]

On August 10, YPF accepted EDENOR’s offer for its 70% MetroGAS interest and its direct 5% MetroENERGÍA interest for $780 million. The transaction was subject to conditions precedent, including regulatory approval. The disclosed price cannot be treated as cash already available at June 30, nor can a signed sale agreement be substituted for evidence of closing.[11][2]

A different transaction did reach a stated closing milestone. On September 14, Vaca Muerta Inversiones, wholly controlled by YPF, assigned a 20% interest in the La Escalonada and Rincón La Ceniza joint-venture contracts to Pluspetrol after conditions were satisfied. VMI’s resulting interest in those contracts was 25%. The completed transfer is separate from the still-conditional MetroGAS sale.[12]

Portfolio transactions can improve strategic concentration while creating accounting charges and transition costs. YPF’s second-quarter discussion included mature-field fair-value changes and commitment reassessments. Selling a higher-cost operation may reduce future lifting cost but also reduce current volumes, transfer or retain liabilities and require cash settlement of specific obligations. The resulting economics depend on the terms, not merely on the number of assets sold.[3] A dated example is the December 18, 2025 sale of YPF’s 50% Profertil interest: the $596 million price was subject to adjustment, the recognized gain was $335 million, and $396 million remained receivable at December 31, 2025. The sale price, accounting gain and cash collected are distinct measures.[1] At June 30, the interim statements reported $432 million of assets held for sale and $981 million of directly associated liabilities, including $975 million of well-abandonment obligations in the conventional-upstream optimization portfolio. The first-half accounting effects included a $133 million loss from changes in the fair value of assets held for sale and a $57 million operating-optimization charge.[2]

The 2025 Form 20-F specifically warns that divested mature fields can leave YPF with well-abandonment and environmental-remediation liabilities under applicable law, even where the buyer contractually assumes those costs.[1]

On May 21, 2026, YPF completed the assignment of the Manantiales Behr conventional concession, its associated transportation concession and inventories to Pecom Servicios Energía (51%) and San Benito Upstream (49%), after the required approvals and conditions were satisfied.[20]

On August 5, 2026, YPF signed separate conditional agreements for the Mendoza Non-Operated cluster with San Benito Upstream for US$205 million and the Chachahuén cluster with Energía Mendocina and Compañía Andina de Petróleo y Gas for US$200 million. The stated effective dates were January 1, 2026 and June 1, 2026, respectively. Applicable VAT and closing adjustments were additional to the agreed prices; both agreements remained subject to conditions precedent when announced.[21][22]

The capital-allocation question is consequently broader than whether capex rises or falls. YPF is simultaneously funding shale growth, maintaining refineries, developing infrastructure, changing asset ownership and managing debt. The discipline test is whether those commitments remain compatible with durable cash generation under more ordinary commodity conditions and whether the proceeds of divestments are realized on the expected timetable.

11 Oil infrastructure: financed construction still needs commissioning

The Vaca Muerta South pipeline, VMOS, is intended to connect Allen with Punta Colorada through approximately 440 kilometers of export-dedicated infrastructure. The August materials described approximately 30% YPF participation, about 80% construction progress as of July and a $2 billion syndicated loan within the broader project-finance structure. These are project-level figures, not amounts to add automatically to YPF parent cash or debt.[3][4] The 2025 annual statements also disclosed that VMOS shareholders, including YPF, had assigned their VMOS shares as collateral for the syndicated loan until completion of the project.[1]

The results release targeted commercial operation by the end of the fourth quarter of 2026 and first oil exports in early 2027. It described an initial approximately 180 thousand barrels per day of capacity and later expansion toward approximately 550 thousand in the second half of 2027. Construction completion, commissioning, first oil and full expansion are separate milestones.[3]

Transport capacity is not the same thing as production attributable to YPF. A shared pipeline serves multiple shippers, and a company’s equity stake in infrastructure can differ from its shipping commitment. The economic benefit includes the ability to move barrels to export destinations, but it depends on tariffs, utilization, committed volumes and the availability of the terminal and supporting facilities.

Oldelval’s latest expansion phase was reported completed in August, adding approximately 150 thousand barrels per day and bringing total transportation capacity to approximately 690 thousand. That completed expansion is distinct from VMOS’s future commissioning sequence. Several pieces of transport infrastructure can advance at different speeds; the basin’s overall capacity cannot be inferred from a single project headline.[3]

The larger LLL Oil proposal carries another horizon. The August presentation described approximately $25 billion of investment over fifteen years and a production plateau of approximately 240 thousand barrels per day from 2032 onward. Those are development-plan figures, not current production or an annual spending commitment already realized. The long investment horizon puts future prices, execution and financing at the center of its economics.[4]

Infrastructure can improve the bargaining position of an upstream producer by expanding market access. It can also introduce new fixed commitments and exposure to underutilization if output or export demand disappoints. The favorable outcome is a coordinated ramp in wells, treatment, transport and sales. A pipeline physically completed ahead of supporting facilities may have less immediate value than its nominal capacity suggests.

The 2025 Form 20-F also describes an eight-year crude-oil export agreement with Empresa Nacional del Petróleo (ENAP) signed in 2025. YPF estimated 95–100 million barrels and approximately $6.5 billion of revenue over the full contractual term, not in a single year.[1]

12 Argentina LNG with Eni and XRG: the investment decision is still ahead

Eni’s October 2, 2026 announcement described Argentina LNG as a project being developed with YPF and XRG using Vaca Muerta gas and floating liquefaction. The initial phase envisaged 12 million tonnes per year through two facilities of six million tonnes each. An investment decision was expected by year-end, production start-up was planned for 2030 and expansion to 18 million tonnes per year was under evaluation.[8]

YPF’s August 13 RIGI application announcement and September 23 financing update described 2031 as the expected start of operations of the two FLNG units, whereas Eni’s October 2 announcement planned production startup in 2030. The counterparties’ published schedules therefore differ. They are development expectations, not a single confirmed commissioning date, and neither announcement reports operating production from these facilities.[8][18][19]

The August announcement estimated $51 billion of investment over the project’s life and approximately $29 billion by 2031, split between approximately $24 billion of infrastructure and $5 billion of upstream development. These are integrated project estimates across participants, not an amount attributed entirely to YPF’s balance sheet. The release described substantial construction financing through a future project-finance structure supported by long-term export agreements.[19]

On September 23, YPF announced a long-term financing proposal of up to $6 billion from the Export-Import Bank of the United States. The proposal covered purchases of U.S. goods and services for infrastructure and production development and remained subject to final approval by EXIM’s board. A proposed financing ceiling is therefore different from approved, disbursed cash or a fully financed project.[18]

Technical and commercial development precede the final project investment decision, and production follows years later. Development agreements and a financing proposal can advance the project while construction and revenue generation remain ahead. The opportunity’s economic contribution is still future-facing.

The June interim statements described agreements under which Eni and XRG would each acquire 32% of UPCO ARLNG, while YPF would retain 36%. At issuance of those statements, the agreements remained subject to closing conditions, including approval of the transfer of the relevant blocks. Eni’s October release describes its 32% upstream participation. These ownership arrangements must be separated from the still-expected project investment decision.[2][8]

The relevant blocks include Meseta Buena Esperanza, Aguada Villanueva and Las Tacanas. The project integrates upstream production, treatment, transport and liquefaction rather than simply attaching a floating facility to existing gas sales. Each part needs to be synchronized: gas must be produced at the required specification and delivered at sufficient pressure and volume before liquefaction can generate saleable cargoes.[2][8]

The investment framework also includes provincial obligations and benefits. The June statements describe the Neuquén agreement’s royalty and tax provisions and infrastructure obligations, with closing conditions that included signing the project FID. Tax stability and investment incentives can support a capital-intensive project, while leaving construction, market, financing and performance risks intact.[2] Under the June 4 Neuquén agreement, the concessionaire’s principal obligation is infrastructure projects totaling $175 million. At issuance of the interim statements, the agreement remained conditional, including on signing the Argentina LNG FID.[2]

For equity analysis, nominal LNG capacity should not be multiplied by a spot gas price and called YPF revenue. Capacity is annual potential at a project level; ownership, utilization, feedgas cost, charter or asset costs, shipping, offtake terms, taxes and financing determine the attributable outcome. Even successful project completion can produce different returns across the upstream, midstream and liquefaction participants.

The next meaningful evidence is consequently more specific than another expression of support. It is the investment decision itself, associated partner commitments, financing terms, engineering and procurement awards, and commercial arrangements that support the construction plan. The end-2026 decision window is a company target, not a guarantee that all those conditions will be completed on schedule.

13 Southern Energy: a separate LNG route with existing contractual commitments

Southern Energy, or SESA, is a separate LNG export venture from the 12-million-tonne Eni–YPF–XRG project. YPF’s August presentation identified a 25% equity interest alongside Pan American Energy, Pampa Energía, Harbour and Golar. Golar’s second-quarter update confirms those participants and describes the Hilli and Esperanza floating facilities contracted for Argentina.[4][17]

Golar reported that Hilli completed its Cameroon contract, departed those waters on August 4 and was repositioning for Singapore modification work. The expected start of its twenty-year Argentina contract was the second half of 2027. Esperanza, the unit previously called MKII, remained under conversion with completion planned for the fourth quarter of 2027 and Argentina contract start-up scheduled for the second half of 2028.[17]

Those milestones are more advanced than an initial memorandum, but the facilities were not yet producing LNG in Argentina in the reported update. Modification, conversion, transport, hookup, commissioning and feedgas supply remain necessary steps. Golar’s financial backlog and tariff-related earnings are Golar’s measures. They cannot be reassigned to YPF simply because YPF owns a minority equity interest in the export venture.

The SESA venture had an executed eight-year agreement with Securing Energy for Europe, SEFE, to sell two million tonnes of LNG annually. Golar also reported EPC awards for the pipeline and compressor plant of San Matías Pipeline and regulatory and environmental approvals. Its August update described pipeline financing discussions as advanced, with a third-quarter closing expectation. That expectation was a financing target, not a statement that the financing had already closed.[17] On June 26, 2026, Ministry of Economy Resolution No. 873/2026 approved the Group’s participation in RIGI for the San Matías Pipeline Project through Sur Inversiones Energéticas. That approval concerns the dedicated gas pipeline, a separate project from Argentina LNG with Eni and XRG.[2]

YPF’s August materials described the dedicated pipeline as approximately 470 kilometers, while Golar described approximately 500 kilometers. Both are approximate project descriptions from the respective companies. The analytical point does not depend on forcing the two rounded lengths into a single false precision: dedicated gas evacuation is required to support year-round operation of the floating facilities.[4][17]

The two LNG routes therefore have different partners, ownership structures, unit sizes, contracts and decision stages. Combining them into an approximately eighteen-million-tonne opportunity can be useful for describing a regional development ambition, but it conceals the project-level conditions unless the components remain explicit. Existing charters and offtake at SESA do not automatically establish financing or FID for Argentina LNG with Eni and XRG.

The operating sequence remains demanding even where contractual progress is clear. The venture must align gas supply, transport availability, facilities and customer commitments. For YPF, the eventual benefit depends on both its venture economics and its role in supplying or developing gas. A share of a project is not a share of every counterpart’s revenue, debt or reported backlog. In 2025 YPF also granted guarantees related to Sur Inversiones Energéticas’ 25% interest in SESA: up to $137.5 million in favor of Golar Hilli Corporation on May 30 and up to $187.5 million in favor of Golar MKII Corporation on October 27. These are disclosed guarantee ceilings, not cash already paid or loans drawn by YPF.[1]

14 YPF Luz: a $430 million minority purchase approved, not a completed takeover

On October 8, YPF’s board approved buying 24.99% of YPF Energía Eléctrica, known as YPF Luz, from BNR Power Investments B.V. for $430 million. The announcement said the transaction was structured with financing from international sources and subject to conditions precedent. Satisfying those conditions would increase YPF’s holding from 75.01% to 100%.[7]

The same disclosure reported 3,764 MW of installed capacity, comprising 2,740 MW thermal and 1,024 MW renewable generation. It cited approximately $479 million of adjusted EBITDA for the twelve months ended June 2026 and $130 million for the second quarter. These are YPF Luz figures at the stated business scope, not another contribution to be added without adjustment to YPF’s already reported consolidated adjusted EBITDA.[7]

The June YPF statements classified YPF Energía Eléctrica as a joint venture despite the large equity stake. Percentage ownership alone therefore does not establish the financial consolidation method. The purchase’s eventual accounting treatment and financial contribution depend on closing and the arrangements that determine control. The headline purchase price is not enough to construct a reliable acquisition accretion estimate.[2]

Strategically, the transaction would deepen YPF’s exposure to power generation while other portfolio actions reduce gas-distribution or mature-field exposure. That can create a more focused energy portfolio, but it also uses capital and introduces financing obligations. A company can sell assets and purchase others in the same strategic program; the net effect depends on proceeds, timing, liabilities and the earnings retained or acquired.

The useful follow-up is a closing disclosure and the resulting financing and accounting detail. Installed MW are a physical capacity measure, while generation, contracted prices, availability and fuel costs determine earnings. Renewable generation and thermal generation have different operating exposures. Their mix makes power a distinct part of YPF’s risk profile rather than a simple substitute for upstream oil cash flow.

The disclosed international financing structure offers more information than an unspecified intention to seek funds, but it does not remove the conditional status of the equity purchase. At the announcement stage, $430 million is the agreed transaction amount; the 100% holding is the result expected after conditions are satisfied. The agreed amount and prospective ownership relate to different stages of the transaction.[7]

15 Government control, governance and the minority shareholder

The 2025 annual report’s ownership table, dated March 9, 2026, listed 200,589,525 Class D shares held by the Argentine National State, representing approximately 51% of capital. It separately listed 3,764 Class A shares held by the State, 7,624 Class B shares held by provincial governments and 40,422 Class C shares held by the employee fund. These are pre-split counts; the split changed the number of shares but not ownership percentages.[1][5]

The table also listed FGS ANSES with 8.040% of capital within the floating Class D category. That category has a company-specific meaning and should not be conflated with a vendor’s freely tradable float estimate. The government-control fact comes from the issuer’s ownership and risk disclosures. A low aggregate insider percentage from a market-data service does not override the State’s controlling position.[1]

Class A shares carry special approval rights. The June statements identify required affirmative government approval for specified mergers, control acquisitions, transfers of all exploration and exploitation rights, voluntary dissolution and a change of corporate or tax domicile outside Argentina. Certain matters also require Congress. The special rights remain relevant beyond simply counting votes at an ordinary shareholder meeting.[2]

The annual report explains that the expropriation legislation contemplated allocation of the expropriated block between the federal government and producing provinces, with transfer still pending at that report’s date. The percentages within that allocation refer to the expropriated block, not to two additional ownership blocks to add to the 51% controlling stake. Confusing those levels would materially misstate ownership.[1]

State control can support coordination on strategic infrastructure, but it can also influence product pricing, investment priorities and management appointments. Minority holders participate in the same economic company without controlling those choices. Improvements in corporate execution do not eliminate the governance structure, and a favorable policy cycle does not guarantee that future governments retain the same objectives.

YPF’s annual controls assessment concluded that internal control over financial reporting was effective at December 31, 2025, with an independent auditor’s attestation. That is a dated reporting-control assessment. It addresses the financial-reporting process rather than guaranteeing that every future investment is attractive or that political interests will align with minority holders.[1]

The governance question is consequently not a binary choice between state support and state risk. Both can exist. What matters is how policy, capital allocation, disclosure and operating performance interact in a specific period, and whether financial obligations and project commitments remain transparent enough to judge the company’s economic position.

In its 2025 annual report, YPF stated that it had no formal dividend policy and had not determined dividends for the fiscal years ended December 31, 2023, 2024 and 2025. Its board evaluates possible distributions against investment needs, debt service, working capital and legal, regulatory, tax and contractual restrictions.[1]

16 Currency and accounting: U.S. dollar functional currency, peso statutory reporting

YPF’s 2025 Form 20-F presents audited consolidated financial statements in U.S. dollars under IFRS as issued by the IASB. YPF’s functional currency is also the U.S. dollar under IAS 21. Separately, Argentine statutory, legal and regulatory financial statements are presented in pesos and filed with the CNV. An Argentine issuer’s domicile therefore does not justify assuming that its SEC financial figures are peso figures translated by a simple average rate.[1]

The June 2026 Form 6-K includes both U.S. dollar interim statements and an English translation of peso statements originally filed in Spanish with the CNV. The dollar interim statements are unaudited and prepared under IAS 34. The peso section states that the Spanish CNV statements prevail in case of translation discrepancies. Language translation and currency translation are separate matters.[2]

For YPF itself, foreign-currency transactions are initially recognized at the exchange rate on the transaction date, with practical monthly-average use when appropriate. Monetary foreign-currency items are translated at settlement or reporting-date rates, with exchange differences in net financial results. Historical-cost non-monetary items retain transaction-date translation. These rules explain why multiplying every peso line by a single closing rate would not recreate the dollar income statement.[1]

Subsidiaries with a hyperinflationary functional currency are restated under IAS 29 before inclusion in the dollar consolidated statements, then translated at the closing exchange rate under the disclosed policy. Translation and net monetary-position effects can appear in other comprehensive income. A difference between net profit and total comprehensive income can therefore reflect meaningful currency and inflation accounting rather than a simple arithmetic mistake.[1][2]

Economic currency risk remains even with dollar functional reporting. Domestic customers, wages, taxes and other costs can be peso-linked, while most financial debt is dollar-denominated. Inflation, exchange rates and the timing of local price adjustments can move differently. The result depends on their combination, not on the presence of a dollar symbol in an investor presentation.[1][3]

Argentina’s exchange regime also affects practical access to currency and cross-border payments. The annual report describes 2025 liberalization measures while retaining risks from regulation and future changes. A historical reform should not be generalized into a permanent guarantee of unrestricted remittances, financing access or dividend conversion. The company’s cash location and obligation currency remain relevant alongside the headline balance sheet.[1]

Comparisons across reporting periods need consistent currency, accounting perimeter and definitions. YPF’s results materials explicitly use the dollar functional-currency framework, while non-IFRS operational measures carry their own adjustments. Maintaining those distinctions is essential to evaluating whether improvement came from production, prices, costs, currency effects or a change in presentation.

17 Nationalization litigation: Argentina’s judgment and YPF’s liability are different

The March 27, 2026 Second Circuit opinion addressed the Petersen and Eton Park litigation arising from the 2012 expropriation. The district court had awarded a combined $16.1 billion against the Argentine Republic while granting judgment for YPF. The appellate court reversed the contract-damages judgment against the Republic, affirmed the judgment for YPF and remanded for further proceedings.[9]

The appellate analysis found the shareholders’ contract-damages claims against the Republic not cognizable under Argentine law. It also affirmed the dismissal of promissory-estoppel claims and YPF’s favorable judgment. The opinion’s discussion of YPF did not find an affirmative obligation to enforce the tender-offer requirements against the Republic. This separates the sovereign’s conduct from the company’s own alleged duties.[9]

YPF’s June statements reported that the appellate decision affirmed no contractual liability or damages owed by YPF on those claims. They also reported that the turnover order in the plaintiffs’ proceedings was vacated, noting that YPF was not a party to those turnover proceedings. Rehearing en banc was denied on June 2 and the mandate issued on June 10.[2]

The procedural story continued. A petition for a writ of certiorari was filed on September 30, 2026 and docketed at the U.S. Supreme Court on October 2 as case 26-442. The docket listed a response due November 2. At October 13, the docket showed the petition stage, not a decision granting review or a new merits judgment imposing liability on YPF.[10]

Filing a petition asks the Supreme Court to consider the case. It does not reverse the appellate decision by itself, establish that review will be granted, or reinstate a corporate damages award. The future legal path depends on court action. The petition-stage uncertainty is real, but its existence is different from the company recording the Republic’s historical judgment as its own debt.

The practical market exposure can extend beyond direct corporate liability. Headlines about sovereign litigation, government-held shares and Argentina’s treatment of investors can influence funding conditions or the country-risk premium applied to YPF. That indirect exposure is analytically distinct from an obligation enforceable against YPF’s operating assets or cash. Combining them into one undifferentiated litigation number obscures the risk.

The 2025 Form 20-F also identifies a separate contractual channel: a change of control, as defined in the relevant debt instruments, could require an offer to repurchase certain bonds at 101% of principal plus accrued interest, and could trigger mandatory prepayment of certain other debt, subject to conditions. YPF stated that the Argentine Republic ceasing to control a majority of voting shares could activate those provisions. That conditional debt mechanism is distinct from damages in the nationalization case.[1]

Other environmental, contractual and regulatory contingencies remain part of the company’s broader disclosures. A favorable result in this nationalization case is not a release from every unrelated legal claim. Equally, the presence of unrelated contingencies does not establish that the nationalization damages are YPF’s. The precise defendant, claim and procedural stage determine what each legal development means.[1][2] In a separate case concerning Neuquina-basin concessionaires, the Argentine Supreme Court dismissed ASSUPA’s lawsuit on May 21, 2026 for failure to meet the minimum requirements for an adequate defense; that claim was definitively dismissed in those proceedings.[2]

18 What would change the interpretation

The operating interpretation would strengthen if later results showed shale growth accompanied by cash generation after investment and financing costs, rather than only a higher production rate. It would weaken if capital per delivered barrel, maintenance needs or working-capital absorption rose enough to offset the gains. Production, costs and cash need to tell a coherent story over several periods, not merely in one favorable quarter.

The infrastructure interpretation would strengthen with commissioning, first exports and dependable utilization. It would weaken if completion dates moved outward while fixed commitments grew or production had to be curtailed for lack of market access. VMOS construction progress and a syndicated loan support a development case, but the next step remains an operating system delivering barrels to customers.[3][4]

The LNG interpretation would become more concrete with a final investment decision and associated financing and commercial terms for the Eni–YPF–XRG project. At SESA, the relevant sequence is facility modification or conversion, pipeline delivery, commissioning and commercial startup. The two routes should be assessed against their own milestones. Completion of one does not complete the other.[8][17]

The financial interpretation would change if disposal proceeds, the YPF Luz purchase or new borrowing materially altered available liquidity and net debt. The June balance sheet is a dated starting position, not a statement that later transactions are already included. A closed transaction and subsequent financial reporting are stronger evidence than extrapolating a purchase price or signed sale into the earlier balance sheet.[7][11]

The legal interpretation would change with an actual Supreme Court order or subsequent merits action. The November 2 docket response date is a procedural date, not a scheduled verdict. The October 29 earnings webcast is a company-announced presentation date, not proof of any future result. Keeping those categories separate makes the next calendar useful without turning dates into promises.[10][6]

The overall editorial assessment is that YPF’s operating transformation is visible in production and second-quarter cash generation, while the company retains material commodity, policy, currency, governance and project risks. The durable question is whether a more shale-focused system can earn and retain cash through a cycle while delivering the infrastructure required for its next stage. Neither a strong quarter nor a large development ambition answers that question alone.